UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
10-Q
(Mark One)
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly
period ended March 31, 2015
Or
☐ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition
period from ________to________
Commission
file number 0-24012
DEEP WELL OIL & GAS, INC.
(Exact
name of registrant as specified in its charter)
Nevada |
|
98-0501168 |
(State or other jurisdiction of
incorporation or organization) |
|
(I.R.S. Employer
Identification No.) |
|
Suite 700, 10150 - 100 Street, Edmonton, Alberta, Canada |
|
T5J 0P6 |
(Address of principal executive offices) |
|
(Zip Code) |
Registrant’s telephone number, including
area code: (780) 409-8144
Former name, former address and former fiscal
year, if changed since last report: not applicable.
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements
for the past 90 days. Yes þ No ☐
Indicate by check mark whether the registrant has submitted electronically
and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule
405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and
post such files). Yes þ No ☐
Indicate by check mark whether the registrant is a large accelerated
filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated
filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
|
Large accelerated
filer ☐ |
|
Accelerated
filer ☐ |
|
Non-accelerated filer
☐ (Do not check if a smaller
reporting company) |
|
Smaller reporting company
þ |
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ
The number of shares of common stock outstanding as of May 15, 2015
was 229,374,605.
TABLE OF CONTENTS
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Page
Number |
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PART
I – FINANCIAL INFORMATION |
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ITEM
1. |
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CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS (unaudited) |
3 |
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ITEM
2. |
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MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
21 |
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ITEM
3. |
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QUANTITATIVE
AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
28 |
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ITEM
4. |
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CONTROLS
AND PROCEDURES |
28 |
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PART
II – OTHER INFORMATION |
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ITEM
1. |
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LEGAL
PROCEEDINGS |
28 |
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ITEM
1A. |
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RISK
FACTORS |
28 |
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ITEM
2. |
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UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
28 |
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ITEM
3. |
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DEFAULTS
UPON SENIOR SECURITIES |
28 |
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ITEM
4. |
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MINE
SAFETY DISCLOSURES |
28 |
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ITEM
5. |
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OTHER
INFORMATION |
29 |
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ITEM
6. |
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EXHIBITS |
30 |
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SIGNATURES |
31 |
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Condensed Consolidated Balance Sheets
March 31, 2015 and September 30, 2014
| |
March 31, | | |
September 30, | |
| |
2015 | | |
2014 | |
| |
(Unaudited) | | |
| |
| |
| | |
| |
ASSETS | |
| | |
| |
Current Assets | |
| | |
| |
Cash and cash equivalents | |
$ | 2,107,058 | | |
$ | 2,324,755 | |
Accounts receivable net of allowance of $Nil (September 30, 2014 - $Nil) | |
| 172,966 | | |
| 1,050,099 | |
Prepaid expenses | |
| 58,014 | | |
| 43,875 | |
| |
| | | |
| | |
Total Current Assets | |
| 2,338,038 | | |
| 3,418,729 | |
| |
| | | |
| | |
Long term investments | |
| 363,292 | | |
| 409,618 | |
Oil and gas properties, net, based on successful efforts method of accounting | |
| 19,615,156 | | |
| 19,604,050 | |
Property and equipment, net | |
| 231,516 | | |
| 259,198 | |
| |
| | | |
| | |
TOTAL ASSETS | |
$ | 22,548,002 | | |
$ | 23,691,595 | |
| |
| | | |
| | |
LIABILITIES | |
| | | |
| | |
Current Liabilities | |
| | | |
| | |
Accounts payable and accrued liabilities | |
$ | 169,545 | | |
$ | 714,198 | |
Accounts payable and accrued liabilities– related parties | |
| 474 | | |
| 16,977 | |
| |
| | | |
| | |
Total Current Liabilities | |
| 170,019 | | |
| 731,175 | |
| |
| | | |
| | |
Asset retirement obligations (Note 10) | |
| 421,645 | | |
| 469,013 | |
| |
| | | |
| | |
TOTAL LIABILITIES | |
| 591,664 | | |
| 1,200,188 | |
| |
| | | |
| | |
SHAREHOLDERS’ EQUITY | |
| | | |
| | |
Common Stock: (Note 11) | |
| | | |
| | |
Authorized: 600,000,000 shares at $0.001 par value | |
| | | |
| | |
Issued and outstanding: 229,374,605 shares | |
| | | |
| | |
(September 30, 2014 – 229,326,987 shares) | |
| 229,374 | | |
| 229,326 | |
Additional paid in capital | |
| 41,635,437 | | |
| 41,040,447 | |
Accumulated Deficit | |
| (19,908,473 | ) | |
| (18,778,366 | ) |
| |
| | | |
| | |
Total Shareholders’ Equity | |
| 21,956,338 | | |
| 22,491,407 | |
| |
| | | |
| | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | |
$ | 22,548,002 | | |
$ | 23,691,595 | |
See accompanying notes to the condensed consolidated financial
statements
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of Operations
and Comprehensive Income (Loss)
For the Three and Six Months Ended March
31, 2015 and 2014
| |
Three Months Ended | | |
Three Months Ended | | |
Six Months Ended | | |
Six Months Ended | |
| |
March 31, 2015 | | |
March 31, 2014 | | |
March 31, 2015 | | |
March 31, 2014 | |
| |
| | |
| | |
| | |
| |
Revenue | |
$ | 83,401 | | |
$ | – | | |
$ | 229,801 | | |
$ | – | |
Royalty expenses | |
| (3,405 | ) | |
| – | | |
| (12,385 | ) | |
| – | |
Revenue, net of royalty | |
| 79,996 | | |
| – | | |
| 217,416 | | |
| – | |
| |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | |
Operating expenses | |
| 348,009 | | |
| – | | |
| 1,114,522 | | |
| – | |
Operating expenses covered by Farmout (Note 3) | |
| (268,013 | ) | |
| – | | |
| (897,106 | ) | |
| – | |
General and administrative | |
| 528,319 | | |
| 360,944 | | |
| 1,097,187 | | |
| 807,214 | |
Depreciation, accretion and depletion | |
| 21,618 | | |
| 24,011 | | |
| 42,820 | | |
| 48,525 | |
| |
| | | |
| | | |
| | | |
| | |
Net loss from operations | |
| (549,937 | ) | |
| (384,955 | ) | |
| (1,140,007 | ) | |
| (855,739 | ) |
| |
| | | |
| | | |
| | | |
| | |
Other income and expenses | |
| | | |
| | | |
| | | |
| | |
Rental and other income | |
| 3,421 | | |
| 3,363 | | |
| 7,203 | | |
| 11,466 | |
Interest income | |
| 1,150 | | |
| 4,867 | | |
| 2,697 | | |
| 6,918 | |
| |
| | | |
| | | |
| | | |
| | |
Net loss and comprehensive loss | |
$ | (545,366 | ) | |
$ | (376,725 | ) | |
$ | (1,130,107 | ) | |
$ | (837,355 | ) |
| |
| | | |
| | | |
| | | |
| | |
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 | | |
| 229,326 | | |
| 229,374 | | |
| 229,326 | |
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 Six Months Ended March 31, 2015 and
2014
| |
March 31, | | |
March 31, | |
| |
2015 | | |
2014 | |
| |
| | |
| |
| |
| | |
| |
Operating Activities | |
| | |
| |
Net loss | |
$ | (1,130,107 | ) | |
$ | (837,355 | ) |
Items not affecting cash: | |
| | | |
| | |
Share based compensation | |
| 590,036 | | |
| 198,700 | |
Depreciation, accretion and depletion | |
| 42,820 | | |
| 48,525 | |
Bad debts | |
| – | | |
| 430 | |
Net changes in non-cash working capital (Note 13) | |
| 301,838 | | |
| (297,993 | ) |
| |
| | | |
| | |
Net Cash Used in Operating Activities | |
| (195,413 | ) | |
| (887,693 | ) |
| |
| | | |
| | |
Investing Activities | |
| | | |
| | |
Purchase of property and equipment | |
| – | | |
| (406 | ) |
Investment in oil and gas properties | |
| (29,088 | ) | |
| (2,625,693 | ) |
Long term investments | |
| 1,802 | | |
| 1,591 | |
| |
| | | |
| | |
Net Cash Used in Investing Activities | |
| (27,286 | ) | |
| (2,624,508 | ) |
| |
| | | |
| | |
Financing Activities | |
| | | |
| | |
Payments on loan payable – related parties | |
| – | | |
| (189,500 | ) |
Proceeds from issuance of common stock | |
| 5,002 | | |
| – | |
| |
| | | |
| | |
Net Cash Provided by (Used in) Financing Activities | |
| 5,002 | | |
| (189,500 | ) |
| |
| | | |
| | |
Decrease in cash and cash equivalents | |
| (217,697 | ) | |
| (3,701,701 | ) |
| |
| | | |
| | |
Cash and cash equivalents, beginning of period | |
| 2,324,755 | | |
| 7,633,009 | |
| |
| | | |
| | |
Cash and cash equivalents, end of period | |
$ | 2,107,058 | | |
$ | 3,931,308 | |
| |
| | | |
| | |
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
March 31, 2015
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 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, 2014.
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, 2014.
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.
Cash and Cash Equivalents
The Company considers all highly
liquid instruments with a maturity of three months or less at the time of issuance to be cash equivalents.
Allowance for Doubtful Accounts
The Company determines allowances
for doubtful accounts based on aging of specific accounts. Accounts receivable are stated at the historical carrying amounts net
of allowances for doubtful accounts and include only the amounts the Company deems to be collectable. The allowance for bad debts
was $nil and $nil at March 31, 2015 and September 30, 2014, respectively.
Crude oil and natural gas properties
The Company uses the successful efforts
method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil
and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells,
and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for
exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred.
Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development
costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately
allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed
as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.
Under the successful efforts method
of accounting, the Company capitalizes exploratory drilling, equipping and facility costs on the balance sheet pending determination
of whether the project has found proved reserves in economically producible quantities. The Company capitalizes costs associated
with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they
relate. If proved reserves are assigned to a project, the associated capitalized costs become part of well equipment and facilities.
However, if proved reserves are not found in a project, the capitalized costs associated with the project are expensed, net of
any salvage value. Total capitalized costs pending the determination of proved reserves were $19.6 million and $19.6 million at
March 31, 2015 and September 30, 2014, respectively.
Property and Equipment
Property and equipment are stated
at cost less accumulated depreciation. Depreciation expense is computed using the declining balance method over the estimated useful
life of the asset. Only half of the depreciation rate is taken in the year of acquisition. The following is a summary of the depreciation
rates used in computing depreciation expense:
|
| |
% | |
|
Software | |
| 100 | |
|
Computer equipment | |
| 55 | |
|
Portable work camp | |
| 30 | |
|
Vehicles | |
| 30 | |
|
Road Mats | |
| 30 | |
|
Wellhead | |
| 25 | |
|
Office furniture and equipment | |
| 20 | |
|
Oilfield Equipment | |
| 20 | |
|
Tanks | |
| 10 | |
Expenditures for major repairs and
renewals that extend the useful life of the asset are capitalized. Minor repair expenditures are charged to expense as incurred.
Leasehold improvements are amortized over the greater of five years or the remaining life of the lease agreement.
Long-Lived Assets
Oil and Gas Properties
- Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events
and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future cash
flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount
is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of
the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash
flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash
flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity
futures price strips, operating and development costs, and a risk-adjusted discount rate.
Non-producing crude oil and natural
gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped
reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis
and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level
at which impairment was assessed. For individually insignificant non-producing properties, impairment losses are recognized by
amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over
the lives of the leases based on experience of successful drilling and the average holding period. The Company’s impairment
assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated
drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Non Oil and Gas Assets
- The Company reviews for the impairment of long-lived assets annually and whenever events or changes in circumstances indicate
that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized when estimated undiscounted
future cash flows expected to result from the use of the asset and its eventual disposition is less than its carrying amount. Impairment
is measured as the amount by which the assets’ carrying value exceeds its fair value. No impairments to the Company’s
long-lived assets were identified or recorded in the six months ended March 31, 2015 or in the fiscal year ended September 30,
2014.
Depreciation, Depletion and
Amortization
Depreciation, depletion and amortization
of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment
and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed crude
oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated
proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural
gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent
reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization
are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever
there is an indication of a need, but at least in conjunction with annual reserve reports. Revisions are accounted for prospectively
as changes in accounting estimates.
Asset Retirement Obligations
The Company accounts for asset retirement
obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment obligations.
The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible long-lived
asset and the fair value of the liability can reasonably be estimated. Upon initial recognition of an asset retirement obligation,
the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities
are accreted for the change in their present value through charges to oil and gas production and well operations costs. The initial
capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion, and amortization.
If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement
obligation and the asset retirement cost.
Revisions in estimated liabilities
can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling
asset retirement obligations. As at March 31, 2015 and September 30, 2014, asset retirement obligations amount to $421,645 and
$469,013, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government
estimates the cost of abandonment and reclamation to be.
Foreign Currency Translation
The functional currency of the Canadian
subsidiaries is the United States dollar. However, the Canadian subsidiaries transact in Canadian dollars. Consequently, monetary
assets and liabilities are remeasured into United States dollars at the exchange rate on the balance sheet date and non-monetary
items are remeasured at the rate of exchange in effect when the assets are acquired or obligations incurred. Revenues and expenses
are remeasured at the average exchange rate prevailing during the period. Foreign currency transaction gains and losses are included
in results of operations.
Accounting Method
The Company recognizes income and
expenses based on the accrual method of accounting.
Dividend Policy
The Company has not yet adopted a
policy regarding payment of dividends.
Financial, Concentration and
Credit Risk
The Company does not have any concentration
or related financial credit risk related to cash as most of the Company’s funds are maintained in a financial institution
which has its deposits fully guaranteed by the Government of Alberta.
The Company is not directly subject
to credit risk resulting from the concentration of its crude oil sales. For the period ending March 31, 2015 and for the year ended
September 30, 2014, the Company has recorded oil sales received from the operator of the Company’s producing properties.
The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s
joint venture partner who sells 100% of the Company’s oil production to one or more purchasers in the oil and gas industry.
The Company does not require collateral and management periodically evaluates the operator’s financial statements and the
collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully
collectable and that the risk of loss is minimal.
Income Taxes
The Company utilizes the liability
method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities are determined based on
the differences between financial reporting and the tax bases of the assets and liabilities, and are measured using the enacted
tax rates and laws that will be in effect when the differences are expected to reverse. An allowance against deferred tax assets
is recorded when it is more likely than not that such tax benefits will not be realized.
Due to the uncertainty regarding
the Company’s profitability, a valuation allowance has been recorded against the future tax benefits of its losses and no
net benefit has been recorded in the consolidated financial statements.
Revenue Recognition
The Company is in the business of
exploring for, developing, producing, and selling crude oil. Crude oil revenue is recognized when the product is taken from the
storage tanks on the lease and delivered to the purchaser and title transfers to the purchaser. Payment is generally received one
to three months after the sale has occurred.
Occasionally the Company may sell
specific leases, and the gain or loss associated with these transactions will be shown separately from the profit or loss from
the operations or sales of oil products. Such gain or losses will be measured and recognized when all of the following have occurred:
(1) there is persuasive evidence of an arrangement to sell; (2) the price of the sale is fixed or determinable; (3) the title to
the lease has transferred; and (4) collection is reasonably assured.
Advertising and Market Development
The Company expenses advertising and market development
costs as incurred.
Basic and Diluted Net Income (Loss) Per Share
Basic net income (loss) per share
amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts
are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been
issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per
share amounts are the same. There were 1,293,684 common stock equivalents excluded from the calculation because their effect would
be antidilutive.
Financial Instruments
Financial instruments include cash
and cash equivalents, accounts receivable, long term investments, investment in equity securities, accounts payable and accounts
payable - related parties. The fair value of these financial instruments approximates their carrying value because of the short-term
maturity of these items unless otherwise noted. The fair value of the investment in equity securities cannot be determined as the
market value is not readily obtainable. The equity securities are reported using the cost method.
Environmental Requirements
At the report date, environmental
requirements related to the oil properties acquired are unknown and therefore an estimate of any future cost cannot be made.
Share-Based Compensation
The Company accounts for stock options
granted to directors, officers, employees and non-employees using the fair value method of accounting. The fair value of stock
options for directors, officers and employees are calculated at the date of grant and is expensed over the vesting period of the
options on a straight-line basis. For non-employees, the fair value of the options is measured on the earlier of the date at which
the counterparty performance is complete or the date at which the performance commitment is reached. The Company uses the Black-Scholes
model to calculate the fair value of stock options issued, which requires certain assumptions to be made at the time the options
are awarded, including the expected life of the option, the expected number of granted options that will vest and the expected
future volatility of the stock. The Company reflects estimates of award forfeitures at the time of grant and revises in subsequent
periods, if necessary, when forfeiture rates are expected to change.
Recently Adopted Accounting Standards
In June 2014, the FASB issued ASU
2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment
to Variable Interest Entities Guidance in Topic 810, Consolidation”. The guidance eliminates the definition of a development
stage entity thereby removing the incremental financial reporting requirements from U.S. GAAP for development or exploration stage
entities, primarily presentation of inception to date financial information. The provisions of the amendments are effective for
annual reporting periods beginning after December 15, 2014, and the interim periods therein. However, early adoption is permitted.
Accordingly, the Company has adopted this standard as of September 30, 2014.
The Company does not expect the adoption
of any other recent accounting pronouncements to have a material impact on the Company’s financial statements.
Estimates and Assumptions
Management uses estimates and assumptions
in preparing financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions
affect the reported amounts of the assets and liabilities, the disclosure of contingent assets and liabilities, and the reported
revenues and expenses. Actual results could vary from the estimates that were used in preparing these consolidated financial statements.
Significant estimates by management
include valuations of oil properties, valuation of accounts receivable, useful lives of long-lived assets, asset retirement obligations,
valuation of share-based compensation, and the realizability of future income taxes.
3. |
OIL AND GAS PROPERTIES |
The Company’s oil sands acreage
as of March 31, 2015, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until the
Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates
of the Company’s nine oil sands leases are as follows:
| 1) | 32 sections of land under 5 oil sands leases are set to expire on July 10, 2018; |
| 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 this
lease into perpetuity. |
Effective September 25, 2014, the
Company, through its subsidiary Deep Well Alberta, entered into a Purchase and Sale agreement with Classic Energy Inc. (“Classic”),
pursuant to which the Company acquired Classic’s 20% working interest in five sections in one Sawn Lake oil sands lease where
the Company already owned working interests. As of September 25, 2014, the Company increased its net acres in the Sawn Lake oil
sands properties from 33,463 to 34,096 net acres.
Lease Rental Commitments
The Company has acquired interests
in certain oil sands properties located in North Central Alberta, Canada. The terms include certain commitments related to oil
sands properties that require the payments of rents as long as the leases are non-producing. As of March 31, 2015, the Company’s
net payments due under this commitment are as follows:
|
| |
(Cdn $) | |
|
2015 | |
$ | 24,147 | |
|
2016 | |
$ | 48,294 | |
|
2017 | |
$ | 48,294 | |
|
2018 | |
$ | 48,294 | |
|
2019 | |
$ | 29,478 | |
|
Subsequent | |
$ | 22,400 | |
The government of Alberta owns this
land and the Company has acquired the rights to perform oil activities on these lands. If the Company meets the conditions of the
leases the Company will then be permitted to drill on and produce oil from the land into perpetuity. These conditions give the
Company until the expiration of the leases to meet the following requirements on its primary oil sands leases:
| 1) | drill 68 wells throughout the 68 sections; or |
| 2) | drill 44 wells within the 68 sections and having acquired and processed two miles of seismic on
each other undrilled section. |
The Company plans to meet the second
of these conditions. As at March 31, 2015 and September 30, 2014, the Company has an interest in ten wells, which can be counted
towards these requirements.
The Company has identified two
other wells drilled on these leases, which may be included in the satisfaction of this requirement. The Company has also acquired
and processed 25 miles of seismic on the leases, which can be counted towards these requirements. Our joint venture partner and
operator of the SAGD Project has also acquired additional seismic that can be used towards our MLE requirements.
The Company follows the successful
efforts method of accounting for costs of oil properties. Under this method, only those exploration and development costs that
relate directly to specific oil reserves are capitalized; costs that do not relate directly to specific reserves are charged to
expense. Producing, non-producing and unproven properties are assessed annually, or more frequently as economic events indicate,
for potential impairment.
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 impairment on a field-by-field basis. No impairment losses were recognized for the period ended March 31, 2015
(September 30, 2014 - $nil).
Capitalized costs of proven oil properties
will be depleted using the unit-of-production method when the property is placed in production.
Substantially all of the Company’s
oil activities are conducted jointly with others. The accounts reflect only the Company’s proportionate interest in such
activities.
Farmout Agreement
On July 31, 2013, the Company entered
into a Farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”)
to fund the Company’s share of the AER approved SAGD Project at the Company’s Sawn Lake heavy oil reservoir in North
Central Alberta, Canada. In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding
for the Company’s portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where
the Company had a working interest of 50% (before the execution of the Farmout Agreement). The Farmee will also provide funding
to cover monthly operating expenses of the Company, of which the first such monthly payment began in respect of the month of August
2013 and shall not to exceed $30,000 per month. In addition, until December 31, 2015, as amended on November 17, 2014, the Farmee
has the option to elect to obtain a working interest of 45% to 50% working interest in the remaining 56 sections of land where
the Company has working interests ranging from 90% to 100%, by committing an additional $110,000,000 of financing to the development
of the Company’s Sawn Lake oil sands properties. As of March 31, 2015, the Farmee has not exercised this option.
Acquisition of Royalty Interests
On March 18, 2014 and June 27, 2014,
the Company, through its 100% wholly owned subsidiary company Northern Alberta Oil Ltd., entered into and subsequently closed two
Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and Transfer Agreements (collectively
the “Agreements”), with the Company’s joint venture partner (“JV Partner”) and one related party
(Mr. Malik Youyou), whereby the Company acquired and cancelled 5.5% of a disputed 6.5% overriding royalty claim (the “Purported
6.5% Royalty”) potentially on some lands owned by the Company. The Company’s counsel and vendor’s counsel negotiated
the terms and conditions of both the “Acquisition of Royalty Interest” and “General Indenture of Conveyance,
Assignment and Transfer” agreements. Although the Company does not confirm the validity of the Purported 6.5% Royalty, the
Company determined that it was in the best interests of its shareholders to come to an arrangement to acquire and cancel most of
the Purported 6.5% Royalty to prevent a potential encumbrance over its land or the possibility of future litigation resulting from
these alleged royalty claims. Pursuant to the terms and conditions of the Agreements to acquire the purported overriding royalty
interest claims, the Company paid the following consideration:
| (i) | US $2,435,124 (Cdn $2,697,600) was paid to the JV Partner for the purchase and transfer of an undivided
3% interest out of the Purported 6.5% Royalty. The consideration paid was the original cost (in Canadian dollars) that the JV Partner
paid to acquire its 3% interest in the Purported 6.5% Royalty. |
| (ii) | US $1,007,000 was paid to Mr. Malik Youyou, who is a director and majority shareholder of the Company,
for the purchase and transfer of an undivided 2.5% interest out of the Purported 6.5% Royalty. The consideration paid was for the
reimbursement of the original cost (in US dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5% Royalty
from an arm’s length third party. |
4. | CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES |
The Company accounts for the cost
of its oil sands projects and continues to capitalize project costs after the completion of drilling, equipping and facility construction
as long as sufficient progress is being made in assessing the oil sands reserves to justify the oil sands project as a producing
well.
For the period ended March 31, 2015,
the Company’s management determined that sufficient progress has been made in assessing its oil sands reserves for continued
capitalization of exploratory drilling, equipping and facility costs. In relation to this sufficient progress assessment of its
oil sands project the Company considered among other criteria; long lead times in getting regulatory approval for oil sands thermal
recovery projects, road bans, winter access only properties and governmental and environmental regulations which can and often
delay development of oil sands projects. Because of these and other factors, the Company’s oil sands project can take significantly
longer to complete than regular conventional drilling programs for lighter oil. To date the Company’s geological, engineering,
economic studies, and AER approved thermal recovery projects; including the Company’s now producing SAGD Project, continue
to lead them to believe that there is continuing progress toward bringing the project to commercial production. Therefore, the
Company has continued to capitalize its costs associated with its oil sands project.
For the Company’s oil sands
projects, exploratory drilling, equipping and facility costs are capitalized on the balance sheet under “Oil and Gas Properties”
line item, pending a determination of whether potentially economic oil sands reserves have been discovered by the drilling effort
to justify oil sands project as a producing well. The Company periodically assesses the exploration drilling, equipping and facility
capitalized costs for impairment and once a determination is made that a well is of no potential economic value, the costs related
to that oil sands project are expensed as dry hole and reported in exploration expense. No impairments to the Company’s long-lived
assets were identified or recorded in the six months ended March 31, 2015 or in the fiscal year ended September 30, 2014.
The following table illustrates capitalized
costs relating to oil producing activities as of March 31, 2015 and September 30, 2014:
|
| |
March 31, 2015 | | |
September 30, 2014 | |
|
| |
| | |
| |
|
Unproved Oil and Gas Properties | |
$ | 19,669,280 | | |
$ | 19,651,296 | |
|
Proved Oil and Gas Properties | |
| 4,568 | | |
| 4,568 | |
|
Accumulated Depreciation and Depletion | |
| (58,692 | ) | |
| (51,814 | ) |
|
| |
| | | |
| | |
|
Net Capitalized Cost | |
$ | 19,615,156 | | |
$ | 19,604,050 | |
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 six
months ended March 31, 2015 and 2014:
|
| |
March 31, 2015 | | |
March 31, 2014 | |
|
Acquisition of Properties: | |
| | |
| |
|
Proved | |
$ | – | | |
$ | – | |
|
Unproved | |
| 17,984 | | |
| 2,614,881 | |
|
Exploration costs | |
| 13,422 | | |
| 6,358 | |
|
Development costs | |
| – | | |
| – | |
6. |
INVESTMENT IN EQUITY SECURITIES |
On February 25, 2005, the Company
acquired an interest in Signet Energy Inc. (“Signet” formerly Surge Global Energy, Inc.) as a result of a Farmout Agreement
dated February 25, 2005. Signet amalgamated with Andora Energy Corporation (“Andora”) in 2007.
As of November 19, 2008, the Company
converted its Signet shares into 2,241,558 shares of Andora, which represents an equity interest in Andora of approximately 2.24%
as of December 31, 2014, which is Andora’s fiscal year end. These shares are carried at a nominal value using the cost method
and their value is included under oil and gas properties on the Company’s balance sheet.
7. |
PROPERTY AND EQUIPMENT |
|
| |
March 31, 2015 | |
|
| |
| | |
Accumulated | | |
Net Book | |
|
| |
Cost | | |
Depreciation | | |
Value | |
|
Computer equipment | |
$ | 32,197 | | |
$ | 31,612 | | |
$ | 585 | |
|
Office furniture and equipment | |
| 34,130 | | |
| 27,605 | | |
| 6,525 | |
|
Software | |
| 5,826 | | |
| 5,826 | | |
| – | |
|
Leasehold improvements | |
| 4,936 | | |
| 4,936 | | |
| – | |
|
Portable work camp | |
| 170,580 | | |
| 149,943 | | |
| 20,637 | |
|
Vehicles | |
| 38,077 | | |
| 33,453 | | |
| 4,624 | |
|
Oilfield equipment | |
| 249,046 | | |
| 146,432 | | |
| 102,614 | |
|
Road mats | |
| 364,614 | | |
| 320,339 | | |
| 44,275 | |
|
Wellhead | |
| 3,254 | | |
| 2,203 | | |
| 1,051 | |
|
Tanks | |
| 96,085 | | |
| 44,880 | | |
| 51,205 | |
|
| |
$ | 998,745 | | |
$ | 767,229 | | |
$ | 231,516 | |
|
| |
September 30, 2014 | |
|
| |
| | |
Accumulated | | |
Net Book | |
|
| |
Cost | | |
Depreciation | | |
Value | |
|
Computer equipment | |
$ | 32,198 | | |
$ | 31,264 | | |
$ | 934 | |
|
Office furniture and equipment | |
| 34,130 | | |
| 26,880 | | |
| 7,250 | |
|
Software | |
| 5,826 | | |
| 5,826 | | |
| – | |
|
Leasehold improvements | |
| 4,936 | | |
| 4,936 | | |
| – | |
|
Portable work camp | |
| 170,580 | | |
| 146,211 | | |
| 24,369 | |
|
Vehicles | |
| 38,077 | | |
| 32,637 | | |
| 5,440 | |
|
Oilfield equipment | |
| 249,045 | | |
| 135,030 | | |
| 114,015 | |
|
Road mats | |
| 364,614 | | |
| 312,525 | | |
| 52,089 | |
|
Wellhead | |
| 3,254 | | |
| 2,053 | | |
| 1,201 | |
|
Tanks | |
| 96,085 | | |
| 42,185 | | |
| 53,900 | |
|
| |
$ | 998,745 | | |
$ | 739,547 | | |
$ | 259,198 | |
There was $27,682 of depreciation
expense for the period ended March 31, 2015 (March 31, 2014 - $36,045 and September 30, 2014 - $72,956).
Long term investments
consist of cash held in trust by the AER which bears interest at a rate of prime minus 0.375% and has no stated date of maturity.
These investments are required by the AER to ensure there are sufficient future cash flows to meet the expected future asset retirement
obligations and are restricted for this purpose.
9. |
SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES |
Accounts payable – related
parties was $475 as of March 31, 2015 (September 30, 2014 - $16,977) for expenses to be reimbursed to directors. This amount is
unsecured, non-interest bearing, and has no fixed terms of repayment.
As of March 31, 2015, officers, directors,
their families, and their controlled entities have acquired 53.54% of the Company’s outstanding common capital stock. This
percentage does not include unexercised warrants or stock options.
The Company incurred expenses $76,005
to one related party, Concorde Consulting, for professional fees and consulting services provided to the Company during the period
ended March 31, 2015 (March 31, 2014 - $83,745). These amounts were fully paid as of March 31, 2015.
10. |
ASSET RETIREMENT OBLIGATIONS |
The total future asset retirement
obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated
costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At March
31, 2015, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $608,438
(September 30, 2014 - $ 689,445). The fair value of the liability at March 31, 2015 is estimated to be $421,645 (September 30,
2014 - $ 469,013) using a risk free rate of 3.74% and an inflation rate of 2%. The actual costs to settle the obligation are expected
to occur in approximately 35 years.
Changes to the asset retirement obligation
were as follows:
|
| |
March 31, 2015 | | |
September 30, 2014 | |
|
Balance, beginning of period | |
$ | 469,013 | | |
$ | 446,155 | |
|
Liabilities incurred | |
| – | | |
| 73,395 | |
|
Effect of foreign exchange | |
| (55,628 | ) | |
| (64,079 | ) |
|
Disposal | |
| – | | |
| (4,045 | ) |
|
Accretion expense | |
| 8,260 | | |
| 17,587 | |
|
Balance, end of period | |
$ | 421,645 | | |
$ | 469,013 | |
On June 20, 2013, the Company completed
a private placement for an aggregate of 850,000 units at a price of $0.05 per unit for an aggregate of $42,500. Each unit consists
of one common share and one common share purchase warrant. Each warrant entitles the holder to purchase one additional common share
at a price of $0.075 per common share for a period of three years from the date of closing, provided that if the closing price
of the common shares of the Company on the principal market on which the shares trade is equal to or exceeds $1.00 for 30 consecutive
trading days, the warrant term shall automatically accelerate to the date which is 30 calendar days following the date that written
notice has been given to the warrant holders. The warrants expire on June 20, 2016. The value of the common shares and the warrants
totalled $27,448 and $15,052, respectively.
On July 31, 2013, the Company completed
a private placement for an aggregate of 45,111,778 common shares for an aggregate of $22,000,000. Pursuant to the subscription
agreement between the Company and investor the Company issued the shares to the investor after September 20, 2013 but before November
30, 2013. No warrants were issued to the investor in connection with this private placement.
Between August 12 and August 15,
2013, six directors and two consultants of the Company acquired a combined total of 3,768,096 common shares, upon exercising stock
options and warrants, at exercise prices ranging from $0.05 to $0.14 per common share for total combined gross proceeds to the
Company of $372,000.
Return of Capital Distribution
On August 9, 2013, the Company approved
a distribution to its shareholders in the amount of $0.07 per share to be payable on September 20, 2013 (the “Payment Date”)
to the holders of record of all the issued and outstanding shares of common stock of the Company as of the close of business on
August 16, 2013, (the “Record Date”). This cash distribution to the Company’s
shareholders was not a dividend paid out of the earnings and profits, but was a non-dividend distribution characterized as a “return
of capital”.
Warrants
On October 10, 2013, the Company extended the expiration
date of two warrants to purchase up to an aggregate of 29,047,617 shares of the Company’s common stock. The exercise price
of the warrants remains unchanged at $0.105 per share. As a result of this extension, the expiration date of the warrants has been
amended from the original expiry date of November 9, 2013 to November 23, 2015.
On June 23, 2014, 47,618 partial warrants were cancelled
and transferred to a non-related party.
On October 3, 2014, a warrant holder
of the Company acquired 47,618 shares of the Company’s common stock, upon exercising warrants, at an exercise price of $0.105
per share of common stock for gross proceeds to the Company of $5,000.
The following
table summarizes the Company’s warrants outstanding as of March 31, 2015:
|
| |
Shares Underlying Warrants Outstanding | | |
Shares Underlying Warrants Exercisable | |
|
Range of Exercise Price | |
Shares Underlying Warrants Outstanding | | |
Weighted Average Remaining Contractual Life | | |
Weighted Average Exercise Price | | |
Shares Underlying Warrants Exercisable | | |
Weighted Average Exercise Price | |
|
| |
| | |
| | |
| | |
| | |
| |
|
$0.105 at March 31, 2015 | |
| 71,857,141 | | |
| 0.65 | | |
| 0.105 | | |
| 71,857,141 | | |
| 0.105 | |
|
$0.075 at March 31, 2015 | |
| 520,000 | | |
| 1.22 | | |
| 0.075 | | |
| 520,000 | | |
| 0.075 | |
|
| |
| 72,377,141 | | |
| 0.65 | | |
| 0.105 | | |
| 72,377,141 | | |
| 0.105 | |
The following
is a summary of warrant activity for the period ended March 31, 2015:
|
| |
Number of Warrants | | |
Weighted Average Exercise Price | | |
Intrinsic
Value | |
|
| |
| | |
| | |
| |
|
Balance, September 30, 2014 | |
| 72,424,759 | | |
$ | 0.105 | | |
$ | 0.215 | |
|
Cancelled | |
| – | | |
| – | | |
| – | |
|
Granted | |
| – | | |
| – | | |
| – | |
|
Exercised | |
| 47,618 | | |
| 0.105 | | |
| – | |
|
Balance, March 31, 2015 | |
| 72,377,141 | | |
$ | 0.105 | | |
$ | – | |
|
Outstanding Warrants, March 31, 2015 | |
| 72,377,141 | | |
$ | 0.105 | | |
$ | – | |
There were 72,377,141 warrants outstanding
as of March 31, 2015 (September 30, 2014 – 72,424,759), which have a historical fair market value of $1,738,336 (September
30, 2013 - $1,743,336).
Measurement Uncertainty for Warrants
The Company used the Black-Scholes
option pricing model (“Black-Scholes”) to value the options and warrants. This model was developed for use in estimating
the fair value of traded “European” options which are liquid and that have no vesting restrictions and are fully transferable.
The stock options that are granted to employees and directors and the warrants attached to the units issued by the Company are
non-transferable and some vest over time, and all are “American” options. Option pricing models require the input of
subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes
in the assumptions. The following assumptions are used in the Black-Scholes option-pricing model:
Expected Term – Expected term
of 5 years represents the period that the Company’s stock-based awards are expected to be outstanding.
Expected Volatility – Expected
volatilities are based on historical volatility of the Company’s stock, adjusted where determined by management for unusual
and non-representative stock price activity not expected to recur. The expected volatility used ranged from 96% to 116%.
Expected Dividend – The Black-Scholes
valuation model calls for a single expected dividend yield as an input. The Company currently pays no dividends and does not expect
to pay dividends in the foreseeable future.
Risk-Free Interest rate – The
Company bases the risk-free interest rate on the implied yield currently available on U.S. Treasury zero-coupon issues with an
equivalent remaining term. The risk-free rate used ranged from 0.62% to 1.31%.
On November 28, 2005, and as amended
on December 4, 2014, the Board of Deep Well adopted the Deep Well Oil & Gas, Inc. Stock Option Plan (the “Plan’).
The Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Plan, is administered
by the Board, permits options to acquire shares of the Company’s common stock (the “Common Shares”) to be granted
to directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons
providing services to the Company or its subsidiaries.
The maximum number of shares, which
may be reserved for issuance under the Plan, may not exceed 10% of the Company’s issued and outstanding Common Shares, subject
to adjustment as contemplated by the Plan. The aggregate number of Common Shares with respect to which options may be vested to
any one person (together with their associates) under the plan, together with all other incentive plans of the Company in any one
year shall not exceed 2% of the total number of Common Shares outstanding, and in total may not exceed 6% of the total number of
Common Shares outstanding.
Prior to October 1, 2013, the Company
had a total of 4,350,000 options outstanding, that were previously granted to directors, consultants and an employee of the Company
on March 23, 2011 and June 20, 2013, to purchase up to 3,450,000 and 900,000 shares, respectively, each of common stock at exercise
prices ranging from $0.14 to $0.05, respectively, of which a total of 950,000 options granted on June 20, 2013 remain unvested.
On October 28, 2013, the Company
granted a contractor an option to purchase 250,000 shares of common stock at an exercise price of $0.30 per Common Share, all vesting
immediately, with a five-year life, for his services in connection with the Farmout Agreement dated July 31, 2013.
On December 4, 2013, the Company
appointed a new director to its Board and in connection with the appointment the Company granted the new director an option to
purchase 450,000 shares each of common stock at an exercise price of $0.34 per Common Share, 150,000 vesting immediately and the
remaining vesting one-third on December 4, 2014, and one-third on December 4, 2015, with a five-year life.
On September 19, 2014, the Company
granted seven of its directors options to purchase 600,000 shares each of common stock at an exercise price of $0.38 per Common
Share, 200,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016,
with a five-year life.
On September 19, 2014, the Company
granted two consultants an option to purchase each 1,200,000 shares each of common stock at an exercise price of $0.38 per Common
Share, 600,000 vesting immediately and remaining vesting on September 19, 2015.
On September 19, 2014, the Company
granted one employee an option to purchase 180,000 shares each of common stock at an exercise price of $0.38 per Common Share,
60,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with
a five-year life.
On November 17, 2014, the Company
appointed a new director to its Board and in connection with the appointment the Company granted the new director an option to
purchase 600,000 shares each of common stock at an exercise price of $0.23 per Common Share, 200,000 vesting immediately and the
remaining vesting one-third on November 17, 2015, and one-third on November 17, 2016, with a five-year life.
For the period ended March 31, 2015,
the Company recorded share based compensation expense related to stock options in the amount of $590,036 (March 31, 2014 –
$198,700) on the stock options that were previously granted. As of March 31, 2015, there was remaining unrecognized compensation
cost of $766,793 related to the non-vested portion of these unit option awards. Compensation expense is based upon straight-line
depreciation of the grant-date fair value over the vesting period of the underlying unit option.
|
| |
Shares Underlying Options Outstanding | | |
Shares Underlying Options Exercisable | |
|
Range of Exercise Prices | |
Shares Underlying Options Outstanding | | |
Weighted Average Remaining Contractual Life | | |
Weighted Average Exercise Price | | |
Shares Underlying Options Exercisable | | |
Weighted Average Exercise Price | |
|
| |
| | |
| | |
| | |
| | |
| |
|
$0.14 at March 31, 2015 | |
| 900,000 | | |
| 0.98 | | |
$ | 0.14 | | |
| 900,000 | | |
$ | 0.14 | |
|
$0.05 at March 31, 2015 | |
| 3,450,000 | | |
| 3.22 | | |
| 0.05 | | |
| 2,500,000 | | |
| 0.05 | |
|
$0.30 at March 31, 2015 | |
| 250,000 | | |
| 3.58 | | |
| 0.30 | | |
| 250,000 | | |
| 0.30 | |
|
$0.34 at March 31, 2015 | |
| 450,000 | | |
| 3.68 | | |
| 0.34 | | |
| 300,000 | | |
| 0.34 | |
|
$0.38 at March 31, 2015 | |
| 6,780,000 | | |
| 4.47 | | |
| 0.38 | | |
| 2,660,000 | | |
| 0.38 | |
|
$0.23 at March 31, 2015 | |
| 600,000 | | |
| 4.64 | | |
| 0.23 | | |
| 200,000 | | |
| 0.23 | |
|
| |
| 12,430,000 | | |
| 3.84 | | |
$ | 0.26 | | |
| 6,810,000 | | |
$ | 0.22 | |
The aggregate intrinsic value of
exercisable options as of March 31, 2015, was $Nil (September 30, 2014 - $0.11).
The following is a summary of stock option activity as
at March 31, 2015:
|
| |
Number of Underlying Shares | | |
Weighted Average Exercise Price | | |
Weighted Average Fair Market Value | |
|
| |
| | |
| | |
| |
|
Balance, September 30, 2014 | |
| 11,830,000 | | |
$ | 0.26 | | |
$ | 0.21 | |
|
| |
| | | |
| | | |
| | |
|
Balance, March 31, 2015 | |
| 12,430,000 | | |
$ | 0.26 | | |
$ | 0.21 | |
|
| |
| | | |
| | | |
| | |
|
Exercisable, March 31, 2015 | |
| 6,810,000 | | |
$ | 0.22 | | |
$ | 0.18 | |
A summary of the options granted
at March 31, 2015 and September 30, 2014 and changes during the periods then ended is presented below:
|
| |
March 31, 2015 | | |
September 30, 2014 | |
|
| |
Shares | | |
Weighted Average Exercise Price | | |
Shares | | |
Weighted Average Exercise Price | |
|
| |
| | |
| | |
| | |
| |
|
Outstanding balance at beginning of period | |
| 11,830,000 | | |
$ | 0.26 | | |
| 900,000 | | |
$ | 0.14 | |
|
| |
| | | |
| | | |
| 3,450,000 | | |
| 0.05 | |
|
Granted- October 28, 2013 | |
| | | |
| | | |
| 250,000 | | |
| 0.30 | |
|
Granted- December 4, 2013 | |
| | | |
| | | |
| 450,000 | | |
| 0.34 | |
|
Granted- September 19, 2014 | |
| | | |
| | | |
| 6,780,000 | | |
| 0.38 | |
|
Granted- November 17, 2014 | |
| 600,000 | | |
| 0.38 | | |
| | | |
| | |
|
Vested- November 17, 2014 | |
| 200,000 | | |
| 0.38 | | |
| | | |
| | |
|
Vested- December 4, 2014 | |
| 150,000 | | |
| 0.34 | | |
| | | |
| | |
|
| |
| | | |
| | | |
| | | |
| | |
|
Outstanding at end of period | |
| 12,430,000 | | |
$ | 0.26 | | |
| 11,830,000 | | |
$ | 0.26 | |
|
Exercisable | |
| 6,810,000 | | |
| 0.22 | | |
| 6,460,000 | | |
| 0.21 | |
There were 5,620,000 unvested stock options outstanding
as of March 31, 2015 (September 30, 2014 – 5,370,000).
Measurement Uncertainty for Stock Options
The Company used the Black-Scholes
option pricing model (“Black-Scholes”) to value the options and warrants. This model was developed for use in estimating
the fair value of traded “European” options which are liquid and that have no vesting restrictions and are fully transferable.
The stock options that are granted to employees and directors and the warrants attached to the units issued by the Company are
non-transferable and some vest over time, and all are “American” options. Option pricing models require the input of
subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes
in the assumptions. The following assumptions are used in the Black-Scholes option-pricing model:
Expected Term – Expected term
of 5 years represents the period that the Company’s stock-based awards are expected to be outstanding.
Expected Volatility – Expected
volatilities are based on historical volatility of the Company’s stock, adjusted where determined by management for unusual
and non-representative stock price activity not expected to recur. The expected volatility used ranged from 96% to 122%.
Expected Dividend – The Black-Scholes
valuation model calls for a single expected dividend yield as an input. The Company currently pays no dividends and does not expect
to pay dividends in the foreseeable future.
Risk-Free Interest rate – The
Company bases the risk-free interest rate on the implied yield currently available on U.S. Treasury zero-coupon issues with an
equivalent remaining term. The risk-free rate used ranged from 0.62% to 1.83%.
13. | CHANGES IN NON-CASH WORKING CAPITAL |
|
| |
Six Months Ended | | |
Six Months Ended | |
|
| |
March 31, 2015 | | |
March 31, 2014 | |
|
| |
| | |
| |
|
Accounts receivable | |
$ | 877,133 | | |
| (102,363 | ) |
|
Prepaid expenses | |
| (14,139 | ) | |
| 3,877 | |
|
Accounts payable | |
| (561,156 | ) | |
| (199,507 | ) |
|
| |
| | | |
| | |
|
| |
$ | 301,838 | | |
| (297,993 | ) |
Compensation to Directors
Since the acquisition of Northern
Alberta Oil Ltd., the Company and Northern have entered into the following contracts with the following companies for the services
of their officers:
| 1) | Portwest Investments Ltd. (“Portwest”), a company owned 100% by Dr. Horst A. Schmid
(the “Consultant”), for providing services to the Company as Chief Executive Officer and President for Cdn $12,500
per month. On July 1, 2005, the Company entered into a consulting agreement (the “Prior Agreement”) with Portwest,
as filed with the Company’s annual report on Form 10-KSB filed on February 23, 2007, and incorporated by reference herein.
On July 10, 2013, the Company and Portwest agreed to amend (the “Amending Agreement”) the Prior Agreement whereby the
following was settled and amended: |
| i. | Effective date of the Amending Agreement will be June 20, 2013; |
| | |
| ii. | Term of Agreement will be until December 31, 2014; |
| | |
| iii. | The fees payable to the Consultant in the Prior Agreement will be terminated and the Company will
grant the Consultant 5-year options on 1,000,000 of its common shares exercisable at $0.05 per share, which was the market price
at that time. One half of these shares were vested immediately and the remaining one half vested on June 20, 2014; |
| | |
| iv. | The Consultant received: |
| a. | Cdn $70,000, and |
| | |
| b. | 850,000 units of the Company’s shares and warrants at a price of $0.05 per unit, which was
the market price at the time. Each unit shall be comprised of one restricted Company common share and one 3 year full warrant entitling
Portwest to be able to purchase another share for $0.075. The warrants expire on June 20, 2016. |
As consideration for the execution
of the Amending Agreement and the Termination of parts of the Prior Agreement, and waiving Cdn $239,528 accrued by the Company
as owing to Portwest.
In the March 31, 2015 quarter end
period, no fees were owed or paid to Portwest. As of September 30, 2013, the Company had settled all outstanding amounts owed to
Portwest.
| 2) | Concorde Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief
Financial Officer to the Company for Cdn $15,000 per month. As of March 31, 2015, the Company did not owe Concorde Consulting any
of this amount. |
Rental Agreement
On January 21, 2014, the Company
renewed its Edmonton office lease commencing effective on January 1, 2014 and expiring on June 30, 2015. The quarterly payments
due are as follows:
|
| |
Cdn $ | |
|
2015 Q3 (April - June) | |
| 9,031 | |
IGM Resources Corp vs. Deep
Well Oil & Gas, Inc., et al – DISMISSED
On February 11, 2014, the Court dismissed,
without any costs to the Company, the Plaintiff’s claims against Deep Well Oil & Gas, Inc. and its subsidiary Northern
Alberta Oil Ltd.
On March 10, 2005, I.G.M. Resources
Corp. (“the Plaintiff”) filed against Classic Energy Inc., 979708 Alberta Ltd., Deep Well Oil & Gas, Inc., Nearshore
Petroleum Corporation, Mr. Steven P. Gawne, Rebekah Gawne, Gawne Family Trust, 1089144 Alberta Ltd., John F. Brown, Diane Lynn
McClaflin, Cassandra Doreen Brown, Elissa Alexandra Brown, Brown Family Trust, Priority Exploration Ltd., Northern Alberta Oil
Ltd. and Gordon Skulmoski (the “IGM Defendants”) a Statement of Claim in the Court of Queen's Bench of Alberta Judicial
District of Calgary. This suit is a part of a series of lawsuits or actions undertaken by the Plaintiff against some of the other
above IGM Defendants.
The Plaintiff was and still is a
minority shareholder of 979708 Alberta Ltd. ("979708"). 979708 was in the business of discovering, assembling and acquiring
oil and gas prospects. In 2002 and 2003, 979708 acquired oil and gas prospects in the Sawn Lake area of Alberta. On or about the
14th of July, 2003, all or substantially all the assets of 979708 were sold to Classic Energy Inc. The Plaintiff claims
the value of the assets sold was far in excess of the value paid for those assets. On April 23, 2004, Northern purchased Classic
Energy Inc.'s assets, some of which are under dispute by the Plaintiff. On June 7, 2005, Deep Well acquired all of the common shares
of Northern thereby giving Deep Well an indirect beneficial interest in the assets in which the Plaintiff is claiming an interest.
The Plaintiff was seeks an order
setting aside the transaction and returning the assets to 979708, compensation in the amount of Cdn $15,000,000, a declaration
of trust declaring that Northern and Deep Well hold all of the assets acquired from 979708 and any property acquired by use of
such assets, or confidential information of 979708, in trust for the Plaintiff.
| 16. | CRUDE OIL AND NATURAL GAS PROPERTY INFORMATION |
Results of Operations from Oil and Gas Producing
Activities
The following table sets forth the
results of the Company’s operations from oil (in the form of bitumen) producing activities from the Company’s Sawn
Lake oil sands properties located in Alberta, Canada, for the period ending March 31, 2015 and for the year ended September 30,
2014:
|
| |
March 31, 2015 | | |
September 30, 2014 | |
|
Oil sales after royalties | |
$ | 217,416 | | |
$ | 47,116 | |
|
| |
| | | |
| | |
|
Production (Operating) expenses | |
| (217,416 | ) | |
| (47,115 | ) |
|
Exploration expenses | |
| (13,422 | ) | |
| (47,182 | ) |
|
Depreciation, accretion and depletion | |
| (41,746 | ) | |
| (97,646 | ) |
|
| |
| (55,168 | ) | |
| (144,827 | ) |
|
| |
| | | |
| | |
|
Income tax expenses | |
| – | | |
| – | |
|
Results of operations from producing activities | |
$ | (55,168 | ) | |
$ | (144,827 | ) |
For the periods ending March 31,
2015 and March 31, 2014, the Company booked oil revenue in the amount of $217,416 and $Nil, respectively, after deduction of royalties.
For the periods ending March 31, 2015 and March 31, 2014, the volumes of oil delivered were booked to be 9,536 and nil barrels,
respectively, net to the Company, before royalties, with an average oil sales price of $24.06 per barrel (Cdn$28.49 per barrel)
for the period ending March 31, 2015. Operating expenses are zero since at this time they were paid for under the Farmout Agreement.
Transportation costs are included in these operating costs. The total share of the material costs and operating expenses of the
Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to the Company of $Nil.
As required by the Farmout Agreement, the Farmee has since paid Cdn $21,466,744 to the operator of the SAGD Project for the Farmee’s
share and the Company’s share of the capital costs and start-up operating expenses of the SAGD Project up to March 31, 2015.
These costs include the capital costs of the drilling of the SAGD well pair; the purchase and transportation of equipment; installation
and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells and
expenditures to connect these water wells with pipelines to the steam plant facility along with a fuel source tie-in pipeline;
emulsion treatment package; Phase 2 front end costs; and the start-up operating expenses associated with the steaming and production
of the SAGD well pair up to March 31, 2015.
Steam Assisted Gravity Drainage Demonstration Project
On July
30, 2013, the Company entered into a Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”) to jointly
participate in an Alberta Energy Regulator (“AER”) approved SAGD Project on one section of land where the Company now
has a 25% working interest (after the execution of the Farmout Agreement as defined below). The SAGD Project is located on section
30-91-12W5 of the Company’s Peace River oil sands properties located in North Central Alberta, Canada (also known as the
Sawn Lake heavy oil reservoir). On August 15, 2013, and in accordance with the SAGD Project Agreement and the Amendment, the Company
served notice (“Notice of Election”) to of the operator of the Company’s election to participate in the SAGD
Project. Upon signing the Notice of Election the Company was required to pay in full the cash calls for the Company’s initial
share of the capital costs of the SAGD Project and in accordance with a Farmout Agreement dated July 31, 2013 the Company has since
paid all cash calls in full to the operator of the SAGD Project.
SAGD Project Phase 1 - The
SAGD Project started with the first phase (“Phase 1”) consisting of the drilling and completion of one SAGD well pair,
the construction of a facility for steam generation, water handling and oil treating, plus water source and disposal facilities,
and pipelines to connect the source wells and fuel tie-in to the SAGD facility. This first phase included start-up steam operations
of the SAGD facility with production commencing on September 16, 2014. The estimated capital costs to complete the SAGD Project
steam plant facility with one SAGD well pair has been estimated by the operator to be Cdn $32.8 million on a 100% working interest
basis, of which the Company’s share is covered under the Farmout Agreement (this estimate does not include start-up operating
expenses to produce bitumen from the first SAGD well pair).
SAGD Project Phase 2 - The
Phase 2 front end work includes preliminary engineering design, regulatory approval, environmental approval work and determining
regulatory requirements sufficient to define the work program, schedule and estimated cost of this second phase which is anticipated
to include the drilling of two additional SAGD well pairs and the associated expansion of the current SAGD steam plant.
Capitalized Costs Relating Specifically to the SAGD
Project
The Company entered into a Farmout
Agreement dated July 31, 2013, whereby the Company’s operating costs of the SAGD Project are paid in full by the Farmee in
accordance with the Farmout Agreement; therefore the Company has not capitalized any of the capital costs and operating expenses
paid by the Farmee to the operator of the SAGD Project. See Note 4 herein “Capitalization of Costs Incurred in Oil and Gas
Activities”.
Costs Incurred in Oil and Gas Property Acquisition,
Exploration, and Development
See Note 5 herein “Exploration
Activities”.
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 the “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, 2014, filed with the Securities and Exchange
Commission on January 13, 2015.
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 quarterly report on Form 10-Q to “$” are
to United States dollars and references to “Cdn$” are to Canadian dollars. On May 14, 2015, the noon rate of exchange
for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.8339 as reported by the Bank of Canada. The following table sets
forth the rates of exchange for the Cdn$, expressed in US dollars, in effect at the end of the following period and the average
noon rate of exchange during such period, based on the noon rates of exchange for such periods as reported by the Bank of Canada.
Period Ending March 31 | |
2015 | | |
2014 | |
Rate at end of the period | |
| 0.7885 | | |
| 0.9047 | |
Average rate for the three month period | |
| 0.8057 | | |
| 0.9064 | |
General Overview
Deep Well Oil & Gas, Inc., along with
its subsidiaries through which it conducts business, is an emerging independent junior oil and gas exploration and development
company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing land base that we
presently control in the Peace River oil sands area in 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 OTCQB marketplace under the symbol DWOG. The OTCQB marketplace
requires companies to be fully compliant in their filing requirements under the Exchange Act and must meet eligibility standards
to trade on OTCQB, which include but are not limited to the submission of an annual verification and management certification
confirming that the listed company is current in its reporting requirements. We maintain a website at www.deepwelloil.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, including the startup of a Steam Assisted Gravity
Drainage Demonstration project (“SAGD Project”), where we have a 25% working interest, which began producing on September
16, 2014. The following table sets forth certain financial information:
| |
Three Months Ended | | |
Three Months Ended | | |
Six Months Ended | | |
Six Months Ended | |
| |
March 31, 2015 | | |
March 31, 2014 | | |
March 31, 2015 | | |
March 31, 2014 | |
| |
| | |
| | |
| | |
| |
Revenue | |
$ | 83,401 | | |
$ | – | | |
$ | 229,801 | | |
$ | – | |
Royalty expenses | |
| (3,405 | ) | |
| – | | |
| (12,385 | ) | |
| – | |
Revenue, net of royalty | |
| 79,996 | | |
| – | | |
| 217,416 | | |
| – | |
| |
| | | |
| | | |
| | | |
| | |
Expenses | |
| | | |
| | | |
| | | |
| | |
Operating expenses | |
| 348,009 | | |
| – | | |
| 1,114,522 | | |
| – | |
Operating expenses covered by Farmout (Note 3) | |
| (268,013 | ) | |
| – | | |
| (897,106 | ) | |
| – | |
General and administrative | |
| 528,319 | | |
| 360,944 | | |
| 1,097,187 | | |
| 807,214 | |
Depreciation, accretion and depletion | |
| 21,618 | | |
| 24,011 | | |
| 42,820 | | |
| 48,525 | |
| |
| | | |
| | | |
| | | |
| | |
Net loss from operations | |
| (549,937 | ) | |
| (384,955 | ) | |
| (1,140,007 | ) | |
| (855,739 | ) |
| |
| | | |
| | | |
| | | |
| | |
Other income and expenses | |
| | | |
| | | |
| | | |
| | |
Rental and other income | |
| 3,421 | | |
| 3,363 | | |
| 7,203 | | |
| 11,466 | |
Interest income | |
| 1,150 | | |
| 4,867 | | |
| 2,697 | | |
| 6,918 | |
| |
| | | |
| | | |
| | | |
| | |
Net loss and comprehensive loss | |
$ | (545,366 | ) | |
$ | (376,725 | ) | |
$ | (1,130,107 | ) | |
$ | (837,355 | ) |
First production of oil in the form of bitumen began on September 16, 2014. For the three month period ending
March 31, 2015, we booked oil revenue in the amount of $83,401 before deduction of royalties. For the three month period ending
March 31, 2015, the volumes of oil delivered were booked to be 5,922 barrels net to our company, before royalties, with an average
oil sales price of $16.51 per barrel (Cdn$20.44 per barrel). For the six month period ending March 31, 2015, we booked oil revenue
in the amount of $229,801 before deduction of royalties. For the six month period ending March 31, 2015, the volumes of oil delivered
were booked to be 9,536 barrels net to our Company, before royalties, with an average oil sales price of $24.06 per barrel (Cdn$28.49
per barrel). The realized sales price of our oil is discounted for diluent, trucking, pipeline and additional treating costs from
the West Texas Intermediate (“WTI”) benchmark price. While oil prices have remained low, the Canadian dollar has weakened
and offset some of the impact. In addition, our fuel gas costs to operate our SAGD Project steam facility plant have declined
similarly to the decline in the WTI benchmark price. Our net operating margin after operating expenses is zero since at this time
any negative operating margins are paid for under the farmout agreement we entered into on July 31, 2013 (the “Farmout Agreement”)
to fund our share of the SAGD Project. Transportation costs are included in these operating costs. Therefore, the total share
of the material 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 (as defined below) has
since paid Cdn$21.5 million to the operator of the SAGD Project for the Farmee’s share and our share of the capital costs
and start-up operating expenses of the SAGD Project up to March 31, 2015. These costs included the drilling of the SAGD well pair;
the purchase and transportation of equipment; installation and construction of the steam plant facility; testing and commissioning;
the purchase of the water source and disposal wells and expenditures to connect these water wells with pipelines to the steam
plant facility along with a fuel source tie-in pipeline; emulsion treatment package; Phase 2 front end costs; and the start-up
operating expenses associated with the steaming and production of the SAGD well pair up to March 31, 2015.
For the three months ended March 31, 2015,
our general and administrative expenses increased by $167,375 compared to the three months ended March 31, 2014, which was primarily
due to (i) an increase of $230,752 in non-cash share based compensation charged to expense, which was mainly due to vested stock
options we granted on September 19, 2014 and November 17, 2014 to our directors and contractors; and (ii) an increase of foreign
exchange loss of $29,832. These increases were offset by (i) a decrease in engineering fees for the preparation of an independent
reserves evaluation of our Sawn Lake properties; and (ii) a decrease in legal fees. 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 $221,203 for the three months
ended March 31, 2015 compared to $314,105 for the three months ended March 31, 2014.
For the six months ended March 31, 2015, our
general and administrative expenses increased by $289,973 compared to the six months ended March 31, 2014, which was primarily
due to (i) an increase of $391,337 in non-cash share based compensation charged to expense, which was mainly due to vested stock
options we granted in 2014 to our directors and contractors as described above. This increase was offset by (i) a decrease in legal
fees of $55,082; and (ii) a decrease of professional fees. We also received $180,000 during the last six 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 $492,017 for the six months ended March 31, 2015
compared to $590,135 for the six months ended March 31, 2014.
For the three months ended March 31, 2015,
our depreciation, depletion, and accretion expense decreased by $2,393 compared to the three months ended March 31, 2014, 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 March 31, 2015.
For the six months ended March 31, 2015, our
depreciation and accretion expense decreased by $5,705 compared to the six months ended March 31, 2014, 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 March 31, 2015.
For the three months ended March 31, 2015,
there were no significant increases or decreases for rental and other income compared to the three months ended March 31, 2014.
For the six months ended March 31, 2015, rental
and other income decreased by $4,263 compared to the six months ended March 31, 2014.
For the three months ended March 31, 2015,
interest income decreased by $3,717 compared to the three months ended March 31, 2014.
For the six months ended March 31, 2015, interest
income decreased by $4,221 compared to the six months ended March 31, 2014.
As a result of the above transactions, we recorded
an increase of $168,641 in our net loss and comprehensive loss from operations for the three months ended March 31, 2015 compared
to the three months ended March 31, 2014. As discussed above, this increase was primarily due to an increase in non-cash share
based compensation expenses and foreign exchange loss.
As a result of the above transactions, we recorded
an increase of $292,752 in our net loss and comprehensive loss from operations for the six months ended March 31, 2015 compared
to the six months ended March 31, 2014. As discussed above, this increase was primarily due to an increase in non-cash share based
compensation expenses.
Operations
As previously disclosed, we entered into the
Farmout Agreement with our new joint venture partner (the “Farmee”), to fund our share of the SAGD Project. The SAGD
Project is located on our Sawn Lake properties in the Peace River oil sands region of Alberta. In accordance with the Farmout Agreement,
the Farmee has agreed to provide up to $40,000,000 for the funding of 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.
Also, the Farmee is required to provide funding to cover our monthly operating expenses not to exceed $30,000 per month. In addition,
as amended on November 17, 2014, the Farmee has the option to elect, prior to December 31, 2015, to obtain additional working interests
ranging from 45% to 50% in the remaining 56 sections of land where we have working interests ranging from 90% to 100%, by committing
an additional $110,000,000 of financing for the development of our Sawn Lake oil sands properties.
The
first oil production from our joint SAGD Project commenced on September 16, 2014 from the first SAGD well pair. The SAGD well
pair was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection
began in May 2014 and circulated for up to four months with production commencing in mid-September 2014 from the Bluesky oil sands
reservoir. The start of our bitumen sales averaged 221 barrels per day, half way through the 3rd thirty day period since the start-up
of production in September of 2014. Production from our joint SAGD Project has since increased significantly. For the month of
March 2015, bitumen sales averaged 319 barrels per day, with a Steam Oil Ratio (“SOR”) of 5.4. In the last 16 days
of March, production averaged 350 barrels per day with an SOR of 4.9. A single daily production peak was achieved in March 2015
at 421 barrels per day. All of these production numbers are on a 100% basis with our Company owning a 25% working interest. Over
the next several months, bitumen production from the SAGD well pair is expected to increase as the steam chamber continues to
develop. Based on the operator's forecasts, the maximum production rates and a stable SOR are expected around September 2015.
The objective of this initial SAGD well pair
is to establish that SAGD technology is effective in producing oil from the Bluesky reservoir formation and to provide valued productivity
information about the reservoir. Results to date indicate that the use of SAGD technology is successful in producing oil in the
form of bitumen from the Bluesky reservoir. Based on 100% working interest (we have 25%), for the months of January, February and
March of 2015, monthly gross oil sales averaged 252, 294 and 319 barrels of oil per day, respectively. These early stage production
numbers along with the steam oil ratios compare favorably to analogous reservoirs in thermal recovery projects operated by other
companies of similar reservoir types that we and the operator of our joint SAGD Project are monitoring and using as a basis of
comparison. The estimated capital costs to complete the SAGD Project steam plant facility with one SAGD well pair has been estimated
by the operator to be Cdn$32.8 million on a 100% working interest basis, of which our share is covered under the Farmout Agreement
(this estimate does not include start-up operating expenses to produce bitumen from the first SAGD well pair).
The drilling of an additional SAGD well pair
and the associated expansion of the current SAGD plant facility has been deferred due to the decline in oil prices. However, the
operator of the SAGD Project intends to proceed with the Phase 2 front-end work, which includes work on preliminary engineering
design, regulatory approvals, environmental approval work and determining regulatory requirements sufficient to define the work
program.
On March 18, 2014 and June 27, 2014, through
our subsidiary company, Northern Alberta Oil Ltd. (“Northern”), we acquired from one of our joint venture partners
(“JV Partner”) and one related party (Mr. Malik Youyou), and subsequently cancelled, 5.5% of a disputed 6.5% overriding
royalty claim (the “Purported 6.5% Royalty”) on certain lands owned by us. Pursuant to the terms and conditions of
the agreements to acquire the purported overriding royalty interest claims, we paid the following consideration:
| (i) | $2,435,124 to our JV Partner for the purchase and transfer of an undivided 3% interest out of the
Purported 6.5% Royalty. The consideration paid was the original cost (in Canadian dollars) that our JV Partner paid to acquire
its 3% interest in the Purported 6.5% Royalty. |
| (ii) | $1,007,000 to Mr. Malik Youyou, who is a director and majority shareholder of our Company, for
the purchase and transfer of an undivided 2.5% interest out of the Purported 6.5% Royalty. The consideration paid was for the reimbursement
of the original cost (in US dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5% Royalty from an arm’s
length third party. |
Although we continue to deny the validity of
the Purported 6.5% Royalty, we determined that it was in the best interests of our shareholders to come to an arrangement to acquire
and cancel most of the Purported 6.5% Royalty to prevent a potential encumbrance over our land or the possibility of future litigation
resulting from this alleged royalty claim.
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. This application,
submitted in early 2012, was an application to modify our previously approved in-situ demonstration project for a well to test
thermal production on our Sawn Lake oil sands leases. This modification changed the vertical cyclic steam stimulation (“CSS”)
well earlier approved, into a thermal recovery project to test two wells that use a horizontal application of CSS. Now that the
start-up data from our joint SAGD project are available, we intend to use that information to start on the front end engineering
of our HCSS Project where we plan to drill two horizontal wells to test the use of HCSS technology.
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). 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 March 31, 2015, our total assets were
$22,548,002 compared to $23,691,595 as of September 30, 2014. This decrease of $1,143,593 in our total assets was primarily due
to a decrease in our accounts receivable, as a result of a subsequent reimbursement of Cdn$1,200,000 from the Farmee in October
2014 for the SAGD Project winterization program.
Our total liabilities as of March 31, 2015
were $591,664 compared to $1,200,188 as of September 30, 2014. This decrease of $608,524 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
$383,535 and which was paid by the Farmee to us under the Farmout Agreement, just before our year end.
Our working capital (current liabilities subtracted
from current assets) is as follows:
| |
Six Months Ended | | |
Year Ended | |
| |
March 31, 2015 | | |
September 30, 2014 | |
Current Assets | |
$ | 2,338,038 | | |
$ | 3,418,729 | |
Current Liabilities | |
| 170,019 | | |
| 731,175 | |
Working Capital | |
$ | 2,168,019 | | |
$ | 2,687,554 | |
As of March 31, 2015,
we had working capital of $2,168,019 compared to a working capital of $2,687,554 as of September 30, 2014. This decrease is mainly
the result of (i) the net change of accounts receivable, offset by the decrease of accounts payable as described above; and (ii)
cash used for general and administrative expenses. As of March 31, 2015, 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 March 31, 2015, we recorded
$156,547 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
Consolidated Statement of Cash Flows under “Operating Activities”, for the six months ended March 31, 2015, our net
cash used in operating activities was $195,413 compared to $887,693 for the six months ended March 31, 2014. This decrease of
$692,280 was primarily the result of non-cash working capital related to accounts receivable and accounts payable as disclosed
above.
As reported on our Consolidated Statement of
Cash Flows under “Investing Activities”, we had a decrease of $2,597,222 on investment in our oil and gas properties
for the six months ended March 31, 2015, compared to the six months ended March 31, 2014. On March 18, 2014, $2,435,124 (Cdn$2,697,600)
was paid to a JV Partner for the purchase and transfer of an undivided 3% interest out of the Purported 6.5% Royalty. The consideration
paid was the original cost (in Canadian dollars) that the JV Partner paid to acquire its 3% interest in the Purported 6.5% Royalty.
As reported on our Consolidated Statement of
Cash Flows under “Financing Activities”, for the six months ended March 31, 2015, we received $5,000 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. As of March 31, 2015, we had no remaining outstanding loan payable.
Our cash and cash
equivalents as of March 31, 2015 was $2,107,058 compared to $3,931,308 as of March 31, 2014. This decrease of $1,824,250 in cash
was primarily due to (i) $1,007,000 used to purchase and cancel a 2.5% interest out of the Purported 6.5% Royalty in June 2014;
and (ii) general and administrative expenses. As of March 31, 2015, 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. We also note that if we issue more
shares of our common stock, our shareholders 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 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 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 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 adopted by provincial
and or federal governments of Canada or are considering implementing, which may also include cap and trade regimes, carbon taxes,
increased efficiency standards, which will increase compliance costs and may 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; |
● | 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, 2014, filed with the SEC on January 13, 2015. 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.
ITEM 3. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
We are a smaller reporting
company as defined by Rule 12b-2 under the Exchange Act and therefore we are not required to provide the information required under
this item.
ITEM 4. |
CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
As of the end of our fiscal quarter ended March
31, 2015, an evaluation of the effectiveness of our “disclosure controls and procedures” (as such term is defined in
Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation
of our principal executive officer and principal financial officer. Based upon that evaluation, our principal executive officer
and principal financial officer have concluded that as of the end of that quarter, our disclosure controls and procedures were
effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is
(i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules
and forms and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial
officer, to allow timely decisions regarding required disclosure.
It should be noted that while our principal
executive officer and principal financial officer believe that our disclosure controls and procedures provide a reasonable level
of assurance that they are effective, they do not expect that our disclosure controls and procedures or internal control over financial
reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable,
not absolute, assurance that the objectives of the control system are met.
Changes In Internal Control Over Financial Reporting
During the fiscal quarter ended March 31,
2015 there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely
to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. |
LEGAL PROCEEDINGS |
None.
Although we are a smaller reporting company
as defined by Rule 12b-2 under the Exchange Act and are therefore not required to provide the information required under this
item, there have been no material changes in our risk factors from those disclosed in our annual report on Form 10-K for the fiscal
year ended September 30, 2014, filed with the SEC on January 13, 2015.
ITEM 2. |
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
None.
ITEM 3. |
DEFAULTS UPON SENIOR SECURITIES |
None.
ITEM 4. |
MINE SAFETY DISCLOSURES |
Not applicable.
ITEM 5. |
OTHER INFORMATION |
Information to be Reported on Form 8-K
Deep Well reported all information that was
required to be disclosed on Form 8-K during the period covered by this quarterly report on Form 10-Q.
Shareholder Nominations
Other than the recent adoption of our corporate
governance and nominating committee charters as previously disclosed in our annual report on Form 10-K for the year ending September
30, 2014, there have been no changes to the procedures by which shareholders may recommend nominees to our Company’s Board
of Directors during the time period covered by this quarterly report on Form 10-Q.
Exhibit No. | |
Description |
31.1 | |
Certification of President and Chief Executive Officer pursuant to Rule 13a-14(a). |
31.2 | |
Certification of Chief Financial Officer pursuant to Rule 13a-14(a). |
32.1 | |
Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350. |
32.2 | |
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350. |
101 | |
Interactive Data Files |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
DEEP WELL OIL & GAS, INC. |
|
|
|
|
By |
/s/ Horst A. Schmid |
|
|
Dr. Horst A. Schmid |
|
|
Chief Executive Officer and President |
|
|
(Principal Executive Officer) |
|
|
|
|
Date |
May 15, 2015 |
|
|
|
|
By |
/s/ Curtis Sparrow |
|
|
Mr. Curtis James Sparrow |
|
|
Chief Financial Officer |
|
|
(Principal Financial and Accounting Officer) |
|
|
|
|
Date |
May 15, 2015 |
31
Exhibit
31.1
Certification
of Chief Executive Officer
Pursuant
to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934
I, Dr. Horst
A. Schmid, President and Chief Executive Officer of Deep Well Oil & Gas, Inc., certify that:
| 1. | I
have reviewed this Quarterly Report on Form 10-Q of Deep Well Oil & Gas, Inc. for
the quarterly period ended March 31, 2015; |
| 2. | Based
on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the
period covered by this report; |
| 3. | Based
on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods presented
in this report; |
| 4. | The
registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| a) | designed
such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this report is being prepared; |
| b) | designed
such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles; |
| c) | evaluated
the effectiveness of the registrant's disclosure controls and procedures and presented
in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation;
and |
| d) | disclosed
in this report any change in the registrant's internal control over financial reporting
that occurred during the registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrant's internal control over financial reporting;
and |
| 5. | The
registrant’s other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant's auditors
and the audit committee of registrant's board of directors (or persons performing the
equivalent functions): |
| a) | all
significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report financial information;
and |
| b) | any
fraud, whether or not material, that involves management or other employees who have
a significant role in the registrant's internal control over financial reporting. |
Date: |
May
15, 2015 |
|
|
|
|
By: |
/s/
Horst A. Schmid |
|
|
Dr. Horst A. Schmid |
|
|
President and
Chief Executive Officer |
|
Exhibit
31.2
Certification
of Chief Financial Officer
Pursuant
to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934
I, Mr. Curtis
James Sparrow, Chief Financial Officer of Deep Well Oil & Gas, Inc., certify that:
| 1. | I
have reviewed this quarterly report on Form 10-Q of Deep Well Oil & Gas, Inc. for
the quarterly period ended March 31, 2015; |
| 2. | Based
on my knowledge, this report does not contain any untrue statement of a material fact
or omit to state a material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with respect to the
period covered by this report; |
| 3. | Based
on my knowledge, the financial statements, and other financial information included in
this report, fairly present in all material respects the financial condition, results
of operations and cash flows of the registrant as of, and for, the periods presented
in this report; |
| 4. | The
registrant’s other certifying officer and I are responsible for establishing and
maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e)
and 15d-15(e)) and internal control over financial reporting (as defined in Exchange
Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
| a) | designed
such disclosure controls and procedures, or caused such disclosure controls and procedures
to be designed under our supervision, to ensure that material information relating to
the registrant, including its consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this report is being prepared; |
| b) | designed
such internal control over financial reporting, or caused such internal control over
financial reporting to be designed under our supervision, to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles; |
| c) | evaluated
the effectiveness of the registrant's disclosure controls and procedures and presented
in this report our conclusions about the effectiveness of the disclosure controls and
procedures, as of the end of the period covered by this report based on such evaluation;
and |
| d) | disclosed
in this report any change in the registrant's internal control over financial reporting
that occurred during the registrant's most recent fiscal quarter (the registrant's fourth
fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrant's internal control over financial reporting;
and |
| 5. | The
registrant’s other certifying officer and I have disclosed, based on our most recent
evaluation of internal control over financial reporting, to the registrant's auditors
and the audit committee of registrant's board of directors (or persons performing the
equivalent functions): |
| a) | all
significant deficiencies and material weaknesses in the design or operation of internal
control over financial reporting which are reasonably likely to adversely affect the
registrant's ability to record, process, summarize and report financial information;
and |
| b) | any
fraud, whether or not material, that involves management or other employees who have
a significant role in the registrant's internal control over financial reporting. |
Date: |
May
15, 2015 |
|
|
|
|
By: |
/s/
Curtis Sparrow |
|
|
Mr. Curtis James
Sparrow |
|
|
Chief Financial
Officer |
|
Exhibit
32.1
Certification
Pursuant To
18
U.S.C. Section 1350,
As
Adopted Pursuant To
Section
906 Of The Sarbanes-Oxley Act Of 2002
In
connection with the Quarterly Report of Deep Well Oil & Gas, Inc. (the “Company”) on Form 10-Q for the period
ended March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dr.
Horst A. Schmid, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations
of the Company.
A
signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission or its staff upon request.
Date: |
May
15, 2015 |
|
|
|
|
By: |
/s/
Horst A. Schmid |
|
|
Dr. Horst A. Schmid |
|
|
President and
Chief Executive Officer |
|
Exhibit
32.2
Certification
Pursuant To
18
U.S.C. Section 1350,
As
Adopted Pursuant To
Section
906 Of The Sarbanes-Oxley Act Of 2002
In
connection with the Quarterly Report of Deep Well Oil & Gas, Inc. (the “Company”) on Form 10-Q for the period
ended March 31, 2015 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mr.
Curtis James Sparrow, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)
the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations
of the Company.
A
signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission or its staff upon request.
Date: |
May
15, 2015 |
|
|
|
|
By: |
/s/
Curtis Sparrow |
|
|
Mr. Curtis James
Sparrow |
|
|
Chief Financial
Officer |
|
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