ITEM
1.
|
CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS
|
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Condensed Consolidated Balance Sheets
June 30, 2017 and September 30, 2016
|
|
June 30,
|
|
|
September 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,159,152
|
|
|
$
|
1,400,922
|
|
Accounts receivable
|
|
|
111,236
|
|
|
|
22,577
|
|
Prepaid expenses
|
|
|
37,122
|
|
|
|
32,951
|
|
|
|
|
|
|
|
|
|
|
Total Current Assets
|
|
|
1,307,510
|
|
|
|
1,456,450
|
|
|
|
|
|
|
|
|
|
|
Long term investments
|
|
|
390,560
|
|
|
|
384,247
|
|
Oil and gas properties, net, based on full cost method of accounting
|
|
|
21,265,643
|
|
|
|
21,164,415
|
|
Property and equipment, net
|
|
|
139,763
|
|
|
|
161,855
|
|
|
|
|
|
|
|
|
|
|
TOTAL ASSETS
|
|
$
|
23,103,476
|
|
|
$
|
23,166,967
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Accounts payable and accrued liabilities
|
|
$
|
116,005
|
|
|
$
|
47,506
|
|
Accounts payable and accrued liabilities – related parties
|
|
|
6,403
|
|
|
|
2,469
|
|
|
|
|
|
|
|
|
|
|
Total Current Liabilities
|
|
|
122,408
|
|
|
|
49,975
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations (Note 7)
|
|
|
470,230
|
|
|
|
452,533
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES
|
|
|
592,638
|
|
|
|
502,508
|
|
(Commitments and contingencies (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2016 – 229,374,605 shares)
|
|
|
229,374
|
|
|
|
229,374
|
|
Additional paid in capital
|
|
|
42,845,292
|
|
|
|
42,842,978
|
|
Accumulated deficit
|
|
|
(20,563,828
|
)
|
|
|
(20,407,893
|
)
|
|
|
|
|
|
|
|
|
|
Total Shareholders’ Equity
|
|
|
22,510,838
|
|
|
|
22,664,459
|
|
|
|
|
|
|
|
|
|
|
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
|
|
$
|
23,103,476
|
|
|
$
|
23,166,967
|
|
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, 2017 and 2016
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30,
2017
|
|
|
June 30,
2016
|
|
|
June 30,
2017
|
|
|
June 30,
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
150,669
|
|
Royalty expenses
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
(22,977
|
)
|
Revenue, net of royalty
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
127,692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
43,392
|
|
|
|
85,045
|
|
|
|
99,879
|
|
|
|
697,814
|
|
Operating expenses covered by Farmout
|
|
|
(43,392
|
)
|
|
|
(85,045
|
)
|
|
|
(99,879
|
)
|
|
|
(570,122
|
)
|
General and administrative
|
|
|
40,865
|
|
|
|
105,465
|
|
|
|
115,472
|
|
|
|
398,929
|
|
Depreciation, accretion and depletion
|
|
|
15,443
|
|
|
|
17,397
|
|
|
|
45,479
|
|
|
|
51,924
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss from operations
|
|
|
(56,308
|
)
|
|
|
(122,862
|
)
|
|
|
(160,951
|
)
|
|
|
(450,853
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental and other income
|
|
|
194
|
|
|
|
142
|
|
|
|
2,531
|
|
|
|
8,425
|
|
Interest income
|
|
|
812
|
|
|
|
896
|
|
|
|
2,485
|
|
|
|
2,626
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss and comprehensive loss
|
|
$
|
(55,302
|
)
|
|
$
|
(121,824
|
)
|
|
$
|
(155,935
|
)
|
|
$
|
(439,802
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss per common share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and Diluted
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
|
$
|
(0.00
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2017
and 2016
|
|
June 30,
|
|
|
June 30,
|
|
|
|
2017
|
|
|
2016
|
|
|
|
|
|
|
|
|
CASH PROVIDED BY (USED IN):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Activities
|
|
|
|
|
|
|
Net loss
|
|
$
|
(155,935
|
)
|
|
$
|
(439,802
|
)
|
Items not affecting cash:
|
|
|
|
|
|
|
|
|
Share-based compensation
|
|
|
2,314
|
|
|
|
185,903
|
|
Depreciation, accretion and depletion
|
|
|
45,479
|
|
|
|
51,924
|
|
Net changes in non-cash working capital (Note 10)
|
|
|
(20,397
|
)
|
|
|
1,362
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Operating Activities
|
|
|
(128,539
|
)
|
|
|
(200,613
|
)
|
|
|
|
|
|
|
|
|
|
Investing Activities
|
|
|
|
|
|
|
|
|
Purchase of equipment
|
|
|
(2,552
|
)
|
|
|
–
|
|
Investment in oil and gas properties
|
|
|
(112,859
|
)
|
|
|
(93,909
|
)
|
Long term investments
|
|
|
2,180
|
|
|
|
2,145
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used in Investing Activities
|
|
|
(113,231
|
)
|
|
|
(91,764
|
)
|
|
|
|
|
|
|
|
|
|
Financing Activities
|
|
|
|
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
–
|
|
|
|
–
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Financing Activities
|
|
|
–
|
|
|
|
–
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents
|
|
|
(241,770
|
)
|
|
|
(292,377
|
)
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, beginning of period
|
|
|
1,400,922
|
|
|
|
1,786,270
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
1,159,152
|
|
|
$
|
1,493,893
|
|
|
|
|
|
|
|
|
|
|
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, 2017
|
1.
|
NATURE OF BUSINESS AND BASIS OF PRESENTATION
|
Nature of Business
Deep Well Oil & Gas, Inc.
was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide
Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective
on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).
These condensed consolidated
financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the
Company”) and the post-split common stock, with $0.001 par value.
Basis of Presentation
The interim condensed consolidated
financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of
the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements
prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) have
been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate
so as to make the information presented not misleading.
These interim condensed consolidated
financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated
financial statements for the year ended September 30, 2016.
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, 2016.
|
2.
|
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|
Basis of Consolidation
These condensed consolidated
financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. (“Northern”)
from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep
Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All
inter-company balances and transactions have been eliminated.
Crude oil and natural gas
properties
The Company follows the full
cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full cost method of accounting
for oil and gas operations requires that all costs associated with the exploration for and development of oil and gas reserves
be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and geophysical expenses,
carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment
and overhead charges directly related to acquisition, exploration and development activities.
Under
the full cost method, oil and gas properties are subject to the ceiling test
performed quarterly.
A
ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre
ceiling”. The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties,
net of accumulated depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated
future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved
properties not being amortized
,
and (C) the lower of cost or fair value of unproved properties
included in the costs being amortized; less (D) related income tax effects. As of June 30, 2017, no ceiling test write-downs were
recorded for the Company’s oil and gas properties.
Costs associated with unproved properties are excluded from the depletion
calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed
annually for impairment. Costs that have been impaired are included in the costs subject to depletion within the full cost pool.
Asset Retirement Obligations
The Company accounts for asset
retirement obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment
obligations. The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible
long-lived asset and the fair value of the liability can reasonably be estimated. Upon initial recognition of an asset retirement
obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the
liabilities are accreted for the change in their present value through charges to oil and gas production and well operations costs.
The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion,
and amortization. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the
asset retirement obligation and the asset retirement cost.
Revisions in estimated liabilities
can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling
asset retirement obligations. As of June 30, 2017 and September 30, 2016, asset retirement obligations amount to $470,230 and $452,533,
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, 2017, the Company has approximately $525,474 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, 2017 the Company recorded
no oil sales, however and for the year ended September 30, 2016, 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 11,530,000 potentially dilutive securities excluded from the the diluted earnings per share
calculation because their effect would be antidilutive.
Recently Adopted Accounting Standards
In 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, 2017, 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. Currently, 11 out of the 17 sections
that contain the majority of the resources identified to date have been granted continuance under the Alberta governmental tenure
guidelines;
|
|
2)
|
31 sections of land under 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 lease terms include certain commitments related to
oil sands properties that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and
Minerals Act of Alberta continued oil sands leases past their expiry dates are subject to escalating rental payments in respect
of each term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs
and development costs that are incurred in the term year of a continued lease. Escalating rent is payable at the end of each term
year, while annual rent for leases are due at the beginning of each term year. Lessees of continued oil sands leases may reduce
or eliminate their escalating rent obligations by conducting exploration or development work, or research, on the non-producing
lease. As of June 30, 2017, excluding any eligible research, exploration and or development costs that may be used to reduce the
Company’s yearly escalating future rents, the following table sets out the estimated net payments due under this commitment,
which could be as high as:
|
|
|
(USD $)
|
|
|
(Cdn $)
|
|
|
2017
|
|
$
|
9,303
|
|
|
$
|
12,073
|
|
|
2018
|
|
$
|
32,069
|
|
|
$
|
41,615
|
|
|
2019
|
|
$
|
20,823
|
|
|
$
|
27,022
|
|
|
2020
|
|
$
|
20,823
|
|
|
$
|
27,022
|
|
|
2021
|
|
$
|
19,788
|
|
|
$
|
25,678
|
|
|
Subsequent
|
|
$
|
177,539
|
|
|
$
|
230,388
|
|
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, 2017.
Capitalized costs of proven oil
properties will be depleted using the unit-of-production method when the property is placed in production.
Substantially all of the Company’s
oil activities are conducted jointly with others. The accounts reflect only the Company’s proportionate interest in such
activities.
|
4.
|
CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES
|
The following table illustrates
capitalized costs relating to oil producing activities for the nine months ended June 30, 2017 and the fiscal year ended September
30, 2016:
|
|
|
June 30,
2017
|
|
|
September 30,
2016
|
|
|
|
|
|
|
|
|
|
|
Unproved Oil and Gas Properties
|
|
$
|
21,347,636
|
|
|
$
|
21,238,052
|
|
|
Proved Oil and Gas Properties
|
|
|
–
|
|
|
|
–
|
|
|
Accumulated Depreciation and Depletion
|
|
|
(81,993
|
)
|
|
|
(73,637
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Net Capitalized Cost
|
|
$
|
21,265,643
|
|
|
$
|
21,164,415
|
|
Depreciation and depletion expense
for the nine months ended June 30, 2017 and 2016 were $8,356 and $8,489 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, 2017 and the fiscal year ended September 30, 2016:
|
|
|
June 30,
2017
|
|
|
September 30,
2016
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Properties:
|
|
|
|
|
|
|
|
Proved
|
|
$
|
|
|
|
$
|
|
|
|
Unproved
|
|
$
|
109,584
|
|
|
$
|
194,037
|
|
|
Exploration costs
|
|
$
|
10,960
|
|
|
$
|
39,658
|
|
|
Development costs
|
|
$
|
|
|
|
$
|
|
|
|
6.
|
SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES
|
Accounts payable – related
parties was $6,403 as of June 30, 2017 (September 30, 2016 - $2,469) 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, 2017, officers,
directors, their families, and their controlled entities have acquired 53.63% of the Company’s outstanding common capital
stock. This percentage does not include unexercised warrants or stock options.
The Company incurred expenses
$104,031 to one related party, Concorde Consulting, and entity controlled by a director, for professional fees and consulting services
provided to the Company during the period ended June 30, 2017 (June 30, 2016 - $101,358). These amounts were fully paid as of June
30, 2017.
|
7.
|
ASSET RETIREMENT OBLIGATIONS
|
The total future asset retirement
obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated
costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the
costs to be incurred in future periods. At June 30, 2017, the Company estimates the undiscounted cash flows related to asset retirement
obligation to total approximately $622,818 (September 30, 2016 - $616,191). The fair value of the liability at June 30, 2017 is
estimated to be $470,230 (September 30, 2016 - $452,533) 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 26 years.
Changes to the asset retirement
obligation were as follows:
|
|
|
June 30,
2017
|
|
|
September 30,
2016
|
|
|
Balance, beginning of period
|
|
$
|
452,533
|
|
|
$
|
426,607
|
|
|
Liabilities incurred
|
|
|
–
|
|
|
|
–
|
|
|
Effect of foreign exchange
|
|
|
5,218
|
|
|
|
9,771
|
|
|
Disposal
|
|
|
–
|
|
|
|
–
|
|
|
Accretion expense
|
|
|
12,479
|
|
|
|
16,155
|
|
|
Balance, end of period
|
|
$
|
470,230
|
|
|
$
|
452,533
|
|
Common Stock Issued and
Outstanding
As of June 30, 2017, the Company
had outstanding 229,374,605 shares of common stock.
Warrants
On November 23, 2016, warrants
to acquire up to 52,155,221 common shares of the Company, expired unexercised. As of June 30, 2017, the Company had no outstanding
warrants.
The
following is a summary of warrant activity for the period ended June 30, 2017:
|
|
|
Number of Warrants
|
|
|
Weighted Average Exercise Price
|
|
|
Intrinsic Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2016
|
|
|
52,155,221
|
|
|
$
|
0.105
|
|
|
$
|
–
|
|
|
Expired at November 23, 2016
|
|
|
(52,155,221
|
)
|
|
|
0.105
|
|
|
|
–
|
|
|
Balance, June 30, 2017
|
|
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding Warrants, June 30, 2017
|
|
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
There were no warrants outstanding
as of June 30, 2017 (September 30, 2016 – there were 52,155,221 warrants outstanding, which had a historical fair market
value of $3,153,216).
For the period ended June 30,
2017, the Company recorded share-based compensation expense related to stock options in the amount of $2,314 (September 30, 2016
– $237,971) on the stock options that were previously granted. As of June 30, 2017, there was no remaining unrecognized compensation
cost of related to option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over
the vesting period of the underlying unit option.
|
|
|
Shares Underlying
Options Outstanding
|
|
|
Shares Underlying
Options Exercisable
|
|
|
Range of Exercise Price
|
|
Shares Underlying Options Outstanding
|
|
|
Weighted Average Remaining Contractual Life
|
|
|
Weighted Average Exercise Price
|
|
|
Shares Underlying Options Exercisable
|
|
|
Weighted Average Exercise Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$0.05 at June 30, 2017
|
|
|
3,450,000
|
|
|
|
0.97
|
|
|
|
0.05
|
|
|
|
3,450,000
|
|
|
|
0.05
|
|
|
$0.30 at June 30, 2017
|
|
|
250,000
|
|
|
|
1.33
|
|
|
|
0.30
|
|
|
|
250,000
|
|
|
|
0.30
|
|
|
$0.34 at June 30, 2017
|
|
|
450,000
|
|
|
|
1.43
|
|
|
|
0.34
|
|
|
|
450,000
|
|
|
|
0.34
|
|
|
$0.38 at June 30, 2017
|
|
|
6,780,000
|
|
|
|
2.22
|
|
|
|
0.38
|
|
|
|
6,780,000
|
|
|
|
0.38
|
|
|
$0.23 at June 30, 2017
|
|
|
600,000
|
|
|
|
2.38
|
|
|
|
0.23
|
|
|
|
600,000
|
|
|
|
0.23
|
|
|
|
|
|
11,530,000
|
|
|
|
1.81
|
|
|
$
|
0.27
|
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
The aggregate intrinsic value
of exercisable options as of June 30, 2017, was $Nil (September 30, 2016 - $Nil).
The following is a summary of stock option activity
as at June 30, 2017:
|
|
|
Number of Underlying Shares
|
|
|
Weighted Average Exercise Price
|
|
|
Weighted Average Fair Market Value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, September 30, 2016
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, June 30, 2017
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable, June 30, 2017
|
|
|
11,530,000
|
|
|
$
|
0.27
|
|
|
$
|
0.22
|
|
There were no remaining unvested stock options outstanding
as of June 30, 2017 (September 30, 2016 – 200,000).
|
10.
|
CHANGES IN NON-CASH WORKING CAPITAL
|
|
|
|
Nine months ended
|
|
|
Nine months Ended
|
|
|
|
|
June 30,
2017
|
|
|
June 30,
2016
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
(88,659
|
)
|
|
$
|
239,632
|
|
|
Prepaid expenses
|
|
|
(4,171
|
)
|
|
|
8,793
|
|
|
Accounts payable
|
|
|
72,433
|
|
|
|
(247,063
|
)
|
|
|
|
$
|
(20,397
|
)
|
|
$
|
1,362
|
|
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 $11,559 per month (Cdn
$15,000 per month). As of June 30, 2017, the Company did not owe Concorde Consulting any of this amount.
Rental Agreement
On June 19, 2017, the Company
renewed its Edmonton office lease commencing effective on July 1, 2017 and expiring on June 30, 2019. As part of the lease renewal
the Company received the first 3 months of basic rent free. The quarterly payments due are as follows:
|
|
|
USD $
|
|
|
Cdn $
|
|
|
2017 Q4 (July - September)
|
|
$
|
–
|
|
|
$
|
–
|
|
|
2018 Q1 (October - December)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
|
2018 Q2 (January - March)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
|
2018 Q3 (April - June)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
|
2018 Q4 (July - September)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
|
2019 Q1 (October - December)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
|
2019 Q2 (January - March)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
|
2019 Q3 (April - June)
|
|
$
|
6,141
|
|
|
$
|
7,969
|
|
In August of 2017, the Company
participated in a well on the Company’s Sawn Lake properties. The well was drilled to a total depth of 681 meters. The results
of this core well were used for an application for continuation of the mineral rights on one of the Company’s oil sands leases.
On November 21, 2017, the Company’s
joint venture partner and operator of two jointly held oil sands leases, where the Company has working interests, submitted two
continuation applications to the Alberta Oil Sands Tenure division to apply to continue two oil sands leases that were set to expire
on July 10, 2018. On January 29, 2018, the Company’s joint venture partner received approval from Alberta Energy, under the
Alberta Oil Sands Tenure Regulation, to continue 2,816 gross hectares (704 hectares net to the Company) of lands, with a non-producing
status, effective July 10, 2018. These two continued leases have no future expiry dates but are subject to yearly escalating rental
payments until they are deemed to be producing leases.
On December 15, 2017, the Alberta
Energy Regulator (“AER”) approved the previously submitted expansion application of the Company’s joint SAGD
Project. 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. 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. First production from 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.
On February 15, 2018, the Company
participated in a well on one of its oil sands leases to acquire cores and logs through the Bluesky formation. The Company is
currently analyzing the cores and logs.
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, 2016, filed with the U.S. Securities and Exchange Commission (“SEC”) on March 8, 2018.
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 April 12, 2018, the daily rate of
exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.7939 as reported by the Bank of Canada. The following table
sets forth the rates of exchange for the Cdn$, 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
|
|
2017
|
|
|
2016
|
|
Rate at end of period
|
|
$
|
0.7706
|
|
|
$
|
0.7687
|
|
Average rate for the three month period
|
|
$
|
0.7436
|
|
|
$
|
0.7760
|
|
General
Overview
Deep
Well Oil & Gas, Inc., along with its subsidiaries through which it conducts business, is an independent junior oil sands exploration
and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil
sands land base where we have working interests ranging from 25% to 100% in the Peace River oil sands area of Alberta, Canada.
Our principal office is located at Suite 700, 10150 - 100 Street, 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. The
following table sets forth summarized financial information:
|
|
Three Months Ended
|
|
|
Three Months Ended
|
|
|
Nine Months Ended
|
|
|
Nine Months Ended
|
|
|
|
June 30, 2017
|
|
|
June 30, 2016
|
|
|
June 30, 2017
|
|
|
June 30, 2016
|
|
Revenue
|
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
150,669
|
|
Provincial royalty expenses
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
(22,977
|
)
|
Revenue, net of royalty
|
|
|
–
|
|
|
|
–
|
|
|
|
–
|
|
|
|
127,692
|
|
Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
43,392
|
|
|
|
85,045
|
|
|
|
99,879
|
|
|
|
697,814
|
|
Operating expense covered by Farmout
|
|
|
(43,392
|
)
|
|
|
(85,045
|
)
|
|
|
(99,879
|
)
|
|
|
(570,122
|
)
|
General and administrative (excluding share-based compensation)
|
|
|
40,865
|
|
|
|
46,841
|
|
|
|
113,158
|
|
|
|
213,026
|
|
Share-based compensation
|
|
|
–
|
|
|
|
58,624
|
|
|
|
2,314
|
|
|
|
185,903
|
|
Depreciation, accretion and depletion
|
|
|
15,443
|
|
|
|
17,397
|
|
|
|
45,479
|
|
|
|
51,924
|
|
Net loss from operations
|
|
|
(56,308
|
)
|
|
|
(122,862
|
)
|
|
|
(160,951
|
)
|
|
|
(450,853
|
)
|
Other income and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Rental and other income
|
|
|
194
|
|
|
|
142
|
|
|
|
2,531
|
|
|
|
8,425
|
|
Interest income
|
|
|
812
|
|
|
|
896
|
|
|
|
2,485
|
|
|
|
2,626
|
|
Net loss and comprehensive loss
|
|
$
|
(55,302
|
)
|
|
$
|
(121,824
|
)
|
|
$
|
(155,935
|
)
|
|
$
|
(439,802
|
)
|
First
production from our present joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began
on September 16, 2014. A majority of our Company’s Joint Venture partners voted to temporarily suspend operations of the
SAGD Project at the end of February 2016, therefore there was no production volumes or revenues for the three month and nine month
periods ending June 30, 2017. For the comparable 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 comparable 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 ending June 30, 2016, the volume
of oil delivered for five months of production 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). 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. 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, 2017, our general and administrative expenses decreased by $64,600 compared to the three months
ended June 30, 2016, which was primarily due to a decrease of $58,624 in non-cash share-based compensation charged to expense.
We also received $90,000 during this quarter from the Farmee in accordance with a Farmout Agreement to offset some of our monthly
expenses. After adjusting out the non-cash items for share-based compensation and foreign exchange loss, and the funds we received
from the Farmee, our general and administrative expenses were $142,904 for the three months ended June 30, 2017 compared to $132,759
for the three months ended June 30, 2016.
For
the nine months ended June 30, 2017, our general and administrative expenses decreased by $283,457 compared to the nine months
ended June 30, 2016, which was primarily due to a decrease of $183,589 in non-cash share-based compensation charged to expense
and a decrease in engineering fees of $44,693. We also received $270,000 during the last nine months from the Farmee in accordance
with the Farmout Agreement, to offset some of our monthly expenses. After adjusting out the non-cash items for share-based compensation
and foreign exchange loss, and the funds we received from the Farmee, our general and administrative expenses were $420,264 for
the nine months ended June 30, 2017 compared to $487,918 for the nine months ended June 30, 2016.
For
the three months ended June 30, 2017, our depreciation, depletion, and accretion expense decreased by $1,954 compared to the three
months ended June 30, 2016, 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, 2017.
For
the nine months ended June 30, 2017, our depreciation and accretion expense decreased by $6,445 compared to the nine months ended
June 30, 2016, 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 nine months ended June 30, 2017.
For
the three months ended June 30, 2017, there were no significant increases or decreases in rental and other income compared to
the three months ended June 30, 2016.
For
the nine months ended June 30, 2017, rental and other income decreased by $5,894 compared to the nine months ended June 30, 2016.
For
the three months ended June 30, 2017, there were no significant increases or decreases in interest income for three months ended
June 30, 2016.
For
the nine months ended June 30, 2017, there were no significant increases or decreases in interest income compared to the nine
months ended June 30, 2016.
As
a result of the above transactions, we recorded a decrease of $66,522 in our net loss for the three months ended June 30, 2017
compared to the three months ended June 30, 2016. As discussed above, this decrease was primarily due to a decrease in non-cash
share-based compensation expenses.
As
a result of the above transactions, we recorded a decrease of $283,867 in our net loss for the nine months ended June 30, 2017
compared to the nine months ended June 30, 2016. As discussed above, this decrease was primarily due to decreases in non-cash
share-based compensation expenses.
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 two oil sands leases 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 temporarily suspend operations of the SAGD Project at the end of February 2016.
The
current SAGD Project has:
|
●
|
confirmed
that the SAGD process works in the Bluesky formation at Sawn Lake;
|
|
●
|
established
characteristics of ramp up through stabilization of SAGD performance;
|
|
●
|
indicated
the productive capability and SOR of the reservoir; and
|
|
●
|
provided
critical information required for well and facility design associated with future commercial development.
|
The
first SAGD well pair, for the SAGD Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length
of 780 meters each. Steam injection commenced in May 2014 and production started in September of 2014. Production from this one
SAGD well pair 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 15, 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 would be a significant step
towards establishing commercially viability at Sawn Lake on a larger scale.
In
August of 2017, we jointly participated in drilling one well on our Sawn Lake properties. This well was drilled to a total depth
of 681 meters.
On
February 15, 2018, we entered into a contribution agreement with a third-party to drill a well on one of our Sawn Lake oil sands
leases in which we acquired cores and logs through the Bluesky formation. We are currently analyzing the cores and logs.
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.
We
currently we have a 90% working interest in six oil sands leases and a 100% working interest in 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 two oil sands
leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous and cover 42,383 gross acres (17,152
gross hectares) with our Company having 33,938 net acres (13,734 net hectares). 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, 2017, our total assets were $23,103,476 compared to $23,166,967 as of September 30, 2016. This decrease of $63,491
was primarily due to cash used for general and administrative expenses, offset by and an increase in our accounts receivable and
oil and gas properties.
Our
total liabilities as of June 30, 2017 were $592,638 compared to $502,508 as of September 30, 2016. This increase of $90,130 in
our total liabilities was primarily due to the increase of 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:
|
|
Nine Months Ended
|
|
|
Year Ended
|
|
|
|
June 30,
2017
|
|
|
September 30, 2016
|
|
Current Assets
|
|
$
|
1,307,510
|
|
|
$
|
1,456,450
|
|
Current Liabilities
|
|
|
122,408
|
|
|
|
49,975
|
|
Working Capital
|
|
$
|
1,185,102
|
|
|
$
|
1,406,475
|
|
As
of June 30, 2017, we had working capital of $1,185,102 compared to a working capital of $1,406,475 as of September 30, 2016. This
decrease of $221,373 is mainly the result of cash used for general and administrative expenses. As of June 30, 2017, 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,
2017, we recorded $25,187 in accounts payable due to the operator for our working interest share of the outstanding monthly operating
expenses of the SAGD Project, of which all is reimbursable by the Farmee in accordance with the Farmout Agreement. Therefore,
this amount is also recorded in accounts receivable to be paid to us from the Farmee to cover our share of the costs of the SAGD
Project.
As
reported on our condensed Consolidated Statement of Cash Flows under “Operating Activities”, for the nine months ended
June 30, 2017, our net cash used in operating activities was $128,539 compared to $200,613 for the nine months ended June 30,
2016. This decrease of $72,074 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
$18,950 in the investment in our oil and gas properties for the nine months ended June 30, 2017, compared to the nine months ended
June 30, 2016. 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, 2017 and June 30, 2016, there was no cash inflow or outflow in financing activities.
Our
cash and cash equivalents as of June 30, 2017 was $1,159,152 compared to $1,493,893 as of June 30, 2016. This decrease of $334,741
in cash was primarily due to general and administrative expenses. As of June 30, 2017, 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.
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:
|
●
|
our current business strategy;
|
|
●
|
our future financial position and projected costs;
|
|
●
|
our projected sources and uses of cash;
|
|
●
|
our plan for future development and operations, including the building
of all-weather roads;
|
|
●
|
our drilling and testing plans;
|
|
●
|
our proposed plans for further thermal in-situ development or demonstration
project or projects;
|
|
●
|
the sufficiency of our capital in order to execute our business plan;
|
|
●
|
our reserves and resources estimates;
|
|
●
|
the timing and sources of our future funding.
|
|
●
|
the quantity and value of our reserves;
|
|
●
|
the intent to issue a distribution to our shareholders;
|
|
●
|
our or our operator’s objectives and plans for our current SAGD
Project;
|
|
●
|
our plans for development of our Sawn
Lake properties;
|
|
●
|
production levels from our current SAGD
Project;
|
|
●
|
costs of our current SAGD Project;
|
|
●
|
funding from the Farmee to pay our costs for the current SAGD project
in connection with the Farmout Agreement;
|
|
●
|
additional sources of funding from the Farmout Agreement;
|
|
●
|
funding from the Farmee to cover our monthly operating expenses;
|
|
●
|
our access and availability to third-party infrastructure;
|
|
●
|
present and future production of our properties; and
|
|
●
|
expectations regarding the ability of
our Company and its subsidiaries to raise capital and to continually add to reserves through acquisitions and development.
|
These
forward-looking statements are based on the beliefs and expectations of our management and are subject to significant risks and
uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ
materially from current expectations and projections. Factors that could cause actual results to differ materially from those
set forward in the forward-looking statements include, but are not limited to:
|
●
|
changes in general business or economic conditions;
|
|
●
|
changes in governmental legislation or regulation that affect our
business;
|
|
●
|
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;
|
|
●
|
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;
|
|
●
|
increase in taxes and changes to existing legislation affecting governmental
royalties or other governmental initiatives;
|
|
●
|
future marketing and transportation of our produced bitumen;
|
|
●
|
our ability to receive approvals from the AER for additional tests
to further evaluate the wells on our lands;
|
|
●
|
our Farmout Agreement and joint operating agreements;
|
|
●
|
opposition to our regulatory requests by various third parties;
|
|
●
|
actions of aboriginals, environmental activists and other industrial
disturbances;
|
|
●
|
the costs of environmental reclamation of our lands;
|
|
●
|
availability of labor or materials or increases in their costs;
|
|
●
|
the availability of sufficient capital to finance our business or
development plans on terms satisfactory to us;
|
|
●
|
adverse weather conditions and natural disasters affecting access
to our properties and well sites;
|
|
●
|
risks associated with increased insurance costs or unavailability
of adequate coverage;
|
|
●
|
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;
|
|
●
|
competition;
|
|
●
|
changes in labor, equipment and capital costs;
|
|
●
|
future acquisitions or strategic partnerships;
|
|
●
|
the risks and costs inherent in litigation;
|
|
●
|
imprecision in estimates of reserves, resources and recoverable quantities
of oil, bitumen and natural gas;
|
|
●
|
product supply and demand;
|
|
●
|
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;
|
|
●
|
future appraisal of potential bitumen,
oil and gas properties may involve unprofitable efforts;
|
|
●
|
the ability to meet minimum level of requirements
to continue our oil sands leases beyond their expiry dates;
|
|
●
|
changes in general business or economic
conditions;
|
|
●
|
risks associated with the finding, determination,
evaluation, assessment and measurement of bitumen, oil and gas deposits or reserves;
|
|
●
|
geological, technical, drilling and processing
problems;
|
|
●
|
third party performance of obligations under contractual arrangements;
|
|
●
|
failure to obtain industry partner and other third party consents
and approvals, when required;
|
|
●
|
treatment under governmental regulatory
regimes and tax laws;
|
|
●
|
royalties payable in respect of bitumen, oil and gas production;
|
|
●
|
unanticipated operating events which can reduce production or cause
production to be shut-in or delayed;
|
|
●
|
incorrect assessments of the value of
acquisitions, and exploration and development programs;
|
|
●
|
stock market volatility and market valuation
of the common shares of our Company;
|
|
●
|
fluctuations in currency and interest rates; and
|
|
●
|
the additional risks and uncertainties,
many of which are beyond our control, referred to elsewhere in this quarterly report and in our other SEC filings.
|
The
preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description
of risks and uncertainties, see the sections entitled “Risk Factors” and “Environmental Laws and Regulations”
of our annual report on Form 10-K for the fiscal year ended September 30, 2016 filed with the SEC on March 8, 2018. 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.