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 December 31, 2019
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 NW, 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.
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||
| None | None | None |
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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit files). Yes þ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ☐ | Accelerated filer ☐ | |
| Non-accelerated filer ☐ | Smaller reporting company þ | |
| Emerging growth company þ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ
As of the date of filing this quarterly report on Form 10-Q with the U.S. Securities and Exchange Commission (the “SEC”), Deep Well Oil & Gas, Inc. had outstanding 230,574,603 shares of common stock.
TABLE OF CONTENTS
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DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Condensed Consolidated Balance Sheets
December 31, 2019 and September 30, 2019
| December 31, 2019 | September 30, | |||||||
|
(Unaudited) | 2019 | |||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 37,706 | $ | 49,715 | ||||
| Accounts receivable | 70,368 | 83,398 | ||||||
| Prepaid expenses | 39,423 | 34,266 | ||||||
| Total Current Assets | 147,497 | 167,379 | ||||||
| Long term investments | 406,576 | 396,782 | ||||||
| Unproved Oil and gas properties, net, based on full cost method of accounting | 22,047,866 | 22,040,307 | ||||||
| Property and equipment, net | 70,146 | 73,509 | ||||||
| TOTAL ASSETS | $ | 22,672,085 | $ | 22,677,977 | ||||
| LIABILITIES | ||||||||
| Current Liabilities | ||||||||
| Accounts payable and accrued liabilities | $ | 91,739 | $ | 69,617 | ||||
| Accounts payable and accrued liabilities – related parties | – | 1,375 | ||||||
| Total Current Liabilities | 91,739 | 70,992 | ||||||
| Asset retirement obligations (Note 7) | 514,970 | 500,392 | ||||||
| TOTAL LIABILITIES | 606,709 | 571,384 | ||||||
| (Commitments and contingencies Note 11) | ||||||||
| SHAREHOLDERS’ EQUITY | ||||||||
| Common Stock: (Note 8) | ||||||||
| Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 230,574,603 shares (September 30, 2019 – 230,574,603 shares) | 230,574 | 230,574 | ||||||
| Additional paid in capital | 43,104,276 | 43,104,276 | ||||||
| Accumulated deficit | (21,269,474 | ) | (21,228,257 | ) | ||||
| Total Shareholders’ Equity | 22,065,376 | 22,106,593 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 22,672,085 | $ | 22,677,977 | ||||
See accompanying notes to the condensed consolidated financial statements
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DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of Operations
For Three Months Ended December 31, 2019 and 2018
| December 31, | December 31, | |||||||
| 2019 | 2018 | |||||||
| Revenue | $ | – | $ | – | ||||
| Royalty refunds (expenses) | – | – | ||||||
| Revenue, net of royalty | – | – | ||||||
| Expenses | ||||||||
| Operating expenses | 27,738 | 39,660 | ||||||
| Operating expenses covered by Farmout | (27,738 | ) | (39,660 | ) | ||||
| General and administrative | 30,321 | 53,855 | ||||||
| Depreciation, accretion and depletion | 10,843 | 11,442 | ||||||
| Net loss from operations | (41,164 | ) | (65,297 | ) | ||||
| Other income and expenses | ||||||||
| Rental and other income | (2,047 | ) | 2,046 | |||||
| Interest income | 1,994 | 1,810 | ||||||
| Net loss | $ | (41,217 | ) | $ | (61,441 | ) | ||
| Net loss per common share | ||||||||
| Basic and Diluted | $ | (0.00 | ) | $ | (0.00 | ) | ||
| Weighted Average Outstanding Shares (in thousands) | ||||||||
| Basic and Diluted | 230,574 | 230,574 | ||||||
See accompanying notes to the condensed consolidated financial statements
2
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of Changes in Shareholders’ Equity
For the Three Months Ended December 31, 2019 and 2018
| Common Shares | Additional Paid in | Subscription | Accumulated | |||||||||||||||||||||
| Shares | Amount | Capital | Receivable | Deficit | Total | |||||||||||||||||||
| For the Three Months Ended December 31, 2018 | ||||||||||||||||||||||||
| Balance at September 30, 2018 | 230,574,603 | $ | 230,574 | $ | 43,104,276 | $ | (15,000 | ) | $ | (21,031,122 | ) | $ | 22,288,728 | |||||||||||
| Subscription receivable collected | – | – | – | 15,000 | – | 15,000 | ||||||||||||||||||
| Net loss for the quarter ended December 31, 2018 | – | – | – | – | (61,441 | ) | (61,441 | ) | ||||||||||||||||
| Balance at December 31, 2018 | 230,574,603 | $ | 230,574 | $ | 43,104,276 | $ | – | $ | (21,092,563 | ) | $ | 22,242,287 | ||||||||||||
| For the Three Months Ended December 31, 2019 | ||||||||||||||||||||||||
| Balance at September 30, 2019 | 230,574,603 | $ | 230,574 | $ | 43,104,276 | $ | – | $ | (21,228,257 | ) | $ | 22,106,593 | ||||||||||||
| Net loss for the quarter ended December 31, 2019 | – | – | – | – | (41,217 | ) | (41,217 | ) | ||||||||||||||||
| Balance at December 31, 2019 | 230,574,603 | $ | 230,574 | $ | 43,104,276 | $ | – | $ | (21,269,474 | ) | $ | 22,065,376 | ||||||||||||
See accompanying notes to the condensed consolidated financial statements
3
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Condensed Consolidated Statements of Cash Flows
For the Three Months Ended December 31, 2019 and 2018
| December 31, | December 31, | |||||||
| 2019 | 2018 | |||||||
| CASH PROVIDED BY (USED IN): | ||||||||
| Operating Activities | ||||||||
| Net loss | $ | (41,217 | ) | $ | (61,441 | ) | ||
| Items not affecting cash: | ||||||||
| Depreciation, accretion and depletion | 10,843 | 11,442 | ||||||
| Net changes in non-cash working capital (Note 10) | 28,620 | (31,856 | ) | |||||
| Net Cash Used in Operating Activities | (1,754 | ) | (81,855 | ) | ||||
| Investing Activities | ||||||||
| Purchase of equipment | – | (534 | ) | |||||
| Investment in oil and gas properties | (12,272 | ) | (50,904 | ) | ||||
| Long term investments | 2,017 | 1,743 | ||||||
| Net Cash Used in Investing Activities | (10,255 | ) | (49,695 | ) | ||||
| Financing Activities | ||||||||
| Subscription receivable collected | – | 15,000 | ||||||
| Net Cash Provided by Financing Activities | – | 15,000 | ||||||
| Decrease in cash and cash equivalents | (12,009 | ) | (116,550 | ) | ||||
| Cash and cash equivalents, beginning of period | 49,715 | 298,241 | ||||||
| Cash and cash equivalents, end of period | $ | 37,706 | $ | 181,691 | ||||
| Supplemental Cash Flow Information: | ||||||||
| Cash paid for interest | $ | – | $ | – | ||||
| Cash paid for income taxes | $ | – | $ | – | ||||
See accompanying notes to the condensed consolidated financial statements
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DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
(Unaudited)
Notes to the Condensed Consolidated Financial Statements
December 31, 2019
| 1. | NATURE OF BUSINESS AND BASIS OF PRESENTATION |
Nature of Business
Deep Well Oil & Gas, Inc. was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).
These condensed consolidated financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the Company”) and the post-split common stock, with $0.001 par value.
Basis of Presentation
The interim condensed consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate so as to make the information presented not misleading.
These interim condensed consolidated financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated financial statements for the year ended September 30, 2019.
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, 2019.
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Basis of Consolidation
These interim condensed consolidated financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. (“Northern”) from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All inter-company balances and transactions have been eliminated.
Crude oil and natural gas properties
The Company follows the full cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full cost method of accounting for oil and gas operations requires that all costs associated with the exploration for and development of oil and gas reserves be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.
Under the full cost method, oil and gas properties are subject to the ceiling test performed quarterly. A ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre ceiling”. The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not being amortized, and (C) the lower of cost or fair value of unproved properties included in the costs being amortized; less (D) related income tax effects. As of December 31, 2019, no ceiling test write-downs were recorded for the Company’s oil and gas properties.
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Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired are included in the costs subject to depletion within the full cost pool.
Asset Retirement Obligations
The Company accounts for asset retirement obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment obligations. The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the fair value of the liability can reasonably be estimated. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to oil and gas production and well operations costs. The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion, and amortization. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.
Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling asset retirement obligations. As of December 31, 2019, and September 30, 2019, asset retirement obligations amount to $514,970 and $500,392, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.
Financial, Concentration and Credit Risk
The Company’s consideration or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit insurance limit. As of December 31, 2019, the Company has approximately $19,458 funds that are in excess of deposit insurance limits, which may have financial credit risk. For the Company funds that are maintained in a financial institution which has its deposits fully guaranteed by CUDGC, there is no financial credit risk.
The Company is not directly subject to credit risk resulting from the concentration of its crude oil sales. For the period ending December 31, 2019 and December 31, 2018 the Company recorded no oil sales.
Basic and Diluted Net Loss Per Share
Basic net loss per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net loss per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were no potentially dilutive securities excluded from the the diluted earnings per share calculation because their effect would be antidilutive.
Recently Adopted Accounting Standards
In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. This ASU does not apply to the Company’s oil sand leases. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements because the Company has no leases that the new accounting standard applies to.
| 3. | OIL AND GAS PROPERTIES |
The Company’s oil sands acreage as of December 31, 2019, covers 19,610 gross acres (13,442 net acres) of land under seven oil sands leases. The lease expiration dates of the Company’s oil sands leases are as follows:
| 1. | Out of 20,242 gross acres (13,284 net acres) under five oil sands leases that were set to expiry on July 10, 2018, 14,549 gross acres (8,571 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. In November of 2017, the Company’s joint venture partner and operator of two of the five oil sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591 gross acres (1,898 net acres) and in January 2018, approval was received from Alberta Energy to continue 6,958 gross acres (1,740 net acres). In June 2018, the Company as operator of three of these five oil sands leases, submitted three continuation applications to the Alberta Oil Sands Tenure division to apply to continue another 7,591 gross acres (6,832 net acres) where resources were identified and in July 2018 and April 2019, approval was received from Alberta Energy to continue 7,591 gross acres (6,832 net acres). Of these five oil sands leases that were set to expiry on July 10, 2018, a total of 5,693 gross acres (4,713 net acres) expired without being continued. These expired lands were primarily areas where the Company determined that there was no or limited exploitable resources. These continued leases are now held by the Company for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases; |
6
| 2. | Out of 19,610 gross acres (17,649 net acres) under the three most northern oil sands leases that were set to expire on August 19, 2019, 1,898 gross acres (1,708 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. In August 2019, the Company as operator of these three most northern leases submitted one continuation application to the Alberta Oil Sands Tenure division to apply to continue 1,898 gross acres (1,708 net acres) and in October 2019, approval was received from Alberta Energy to continue 1,898 gross acres (1,708 net acres). Of these three most northern oil sands leases that were set to expiry on August 19, 2019, a total of 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where the Company determined that there was no or limited exploitable resources. This one partially continued lease is now held by the Company for perpetuity, subject to yearly escalating rental payments until the lease is deemed to be a producing lease; and |
| 3. | 3,163 gross acres (3,163 net acres) under one oil sands lease are set to expire on April 9, 2024. It is the Company’s opinion that they have already met the governmental requirements for this lease, and they will be applying to continue this lease into perpetuity. |
Lease Rental Commitments
The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The lease terms include certain commitments related to oil sands properties that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta continued oil sands leases past their expiry dates are subject to escalating rental payments in respect of each term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease. Escalating rent is payable at the end of each term year, while annual rent for leases are due at the beginning of each term year. Lessees of continued oil sands leases may reduce or eliminate their escalating rent obligations by conducting exploration or development work, or research, on the non-producing lease. As of December 31, 2019, excluding any eligible research, exploration and or development costs that may be used to reduce the Company’s yearly escalating future rents, the following table sets out the estimated net payments due under this commitment, which could be as high:
| (USD $) | (Cdn $) | |||||||
| 2020 | $ | 20,598 | $ | 26,754 | ||||
| 2021 | $ | 23,228 | $ | 30,170 | ||||
| 2022 | $ | 30,204 | $ | 39,230 | ||||
| 2023 | $ | 31,800 | $ | 41,303 | ||||
| 2024 | $ | 27,425 | $ | 35,621 | ||||
| Subsequent | $ | 153,209 | $ | 198,998 | ||||
The Company follows the full cost method of accounting for costs of oil properties. Under this method, oil and gas properties, for which no proved reserves have been assigned, must be assessed at least annually to ascertain whether or not a write down should occur. Unproven properties are assessed annually, or more frequently as economic events indicate, for potential write down.
Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. No write downs were recognized for the period ended December 31, 2019.
Capitalized costs of proven oil properties will be depleted using the unit-of-production method when the property is placed in production.
Many of the Company’s oil activities are conducted jointly with others. The accounts reflect only the Company’s proportionate interest in such activities.
| 4. | CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES |
The following table illustrates capitalized costs relating to oil producing activities for the three months ended December 31, 2019 and the fiscal year ended September 30, 2019:
| December 31, 2019 | September 30, 2019 | |||||||
| Unproved Oil and Gas Properties | $ | 22,157,718 | $ | 22,147,367 | ||||
| Accumulated Depreciation and Depletion | (109,852 | ) | (107,060 | ) | ||||
| Net Capitalized Cost | $ | 22,047,866 | $ | 22,040,307 | ||||
Depreciation and depletion expense for the three months ended December 31, 2019 and 2018 were $2,785 and $2,785 respectively.
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| 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 three months ended December 31, 2019 and the fiscal year ended September 30, 2019:
| December 31, 2019 | September 30, 2019 | |||||||
| Acquisition of Properties: | ||||||||
| Proved | $ | – | $ | – | ||||
| Unproved | $ | – | $ | – | ||||
| Exploration costs | $ | 10,351 | $ | 75,580 | ||||
| Development costs | $ | – | $ | – | ||||
| 6. | SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES |
Accounts payable – related parties were $Nil as of December 31, 2019 (September 30, 2019 - $1,375) for expenses to be reimbursed to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.
As of December 31, 2019, officers, directors, their families, and their controlled entities have acquired 53.96% of the Company’s outstanding common capital stock.
The Company incurred expenses $34,092 to one related party, Concorde Consulting, an entity controlled by a director, for professional fees and consulting services provided to the Company during the period ended December 31, 2019 (December 31, 2018 - $34,088). These amounts were fully paid as of December 31, 2019.
| 7. | ASSET RETIREMENT OBLIGATIONS |
The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At December 31, 2019, the Company estimates the undiscounted cash flows related to asset retirement obligations to total approximately $622,253 (September 30, 2019 - $610,291). The fair value of the liability at December 31, 2019 is estimated to be $514,970 (September 30, 2019 - $500,392) 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 23 years.
Changes to the asset retirement obligation were as follows:
December 31, 2019 | September 30, 2019 | |||||||
| Balance, beginning of period | $ | 500,392 | $ | 493,467 | ||||
| Liabilities incurred | – | – | ||||||
| Effect of foreign exchange | 9,884 | (11,081 | ) | |||||
| Disposal | – | – | ||||||
| Accretion expense | 4,694 | 18,006 | ||||||
| Balance, end of period | $ | 514,970 | $ | 500,392 | ||||
| 8. | COMMON STOCK |
Common Stock Issued and Outstanding
As of December 31, 2019, the Company had outstanding 230,574,603 shares of common stock.
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| 9. | STOCK OPTIONS |
On November 17, 2019, 600,000 stock options previously granted on November 17, 2014 to one director expired unexercised.
The following is a summary of stock option activity as at December 31, 2019:
| Number of Underlying Shares | Weighted Average Exercise Price | Weighted Average Fair Market Value | ||||||||||
| Balance, September 30, 2019 | 600,000 | $ | 0.23 | $ | 0.18 | |||||||
| Expired, November 17, 2019 | (600,000 | ) | 0.23 | 0.18 | ||||||||
| Balance, December 31, 2019 | – | $ | – | $ | – | |||||||
| Exercisable, December 31, 2019 | – | $ | – | $ | – | |||||||
| 10. | CHANGES IN NON-CASH WORKING CAPITAL |
| Three months ended | Three months Ended | |||||||
December 31, 2019 | December 31, 2018 | |||||||
| Accounts receivable | $ | 13,030 | $ | (40,607 | ) | |||
| Prepaid expenses | (5,157 | ) | 4,835 | |||||
| Accounts payable | 20,747 | 3,916 | ||||||
| $ | 28,620 | $ | (31,856 | ) | ||||
| 11. | COMMITMENTS |
Compensation to Executive Officers
Concorde Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for $11,364 per month (Cdn $15,000 per month). As of December 31, 2019, the Company did not owe Concorde Consulting any of this amount.
Office Lease
The Company is currently negotiating a one-year extension to its office lease which expired on June 30, 2019. The Company has paid the landlord the monthly rentals it understands to be due as the landlord finalizes a lease agreement extension with the Company.
| 12. | LEGAL ACTIONS |
On October 28, 2019, Provident Premier Master Fund Ltd. (the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”) in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim had been filed on November 1, 2018 but the Company states that it had never been served so the Company was not aware of it. The Plaintiff claims that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all petroleum substances produced, saved and marketed from six of the Company’s oil sands leases located within the Company’s Sawn Lake properties. The Plaintiff seeks: 1) A declaration that the Plaintiff is the legal owner of 0.67% of the GORR payable on all oil sands produced from the lands which is payable by one or more of the Defendants; 2) An accounting to determine the amount of the outstanding royalty of which judgment is estimated by the Plaintiff to be in the amount of $100,000 Cdn; and 3) Interest and costs.
The Company continues to deny the validity of the Purported 6.5% Royalty in the first instance. As well, if the Purported 6.5% Royalty was valid, which is denied, it was not a gross overriding interest, but rather an overriding interest, which allowed for the deduction of operating and marketing costs. The Company plans to vigorously defend itself against the Plaintiff’s claims. As at December 31, 2019, no contingent liability has been recorded, as a successful outcome for the Plaintiff is not probable.
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| ITEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. For the purpose of this discussion, unless the context indicates another meaning, the terms: “Deep Well,” “Company,” “we,” “us,” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries. This discussion includes forward-looking statements that reflect our current views with respect to future events and financial performance that involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding – Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors” and “Environmental Laws and Regulations” disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, 2019, filed with the U.S. Securities and Exchange Commission (“SEC”) and the Alberta Securities Commission (“ASC”) on SEDAR on January 13, 2020. Our Annual Report on Form 10-K can be downloaded from our website at www.deepwelloil.com.
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 (“US”) dollars and references to “Cdn$” are to Canadian dollars. The following table sets forth the rates of exchange for the Cdn$, expressed in US dollars, in effect at the end of the following periods and the average rates of exchange during such periods, based on the rates of exchange for such periods as reported by the Bank of Canada.
| Period Ending December 31 | 2019 | 2018 | ||||||
| Rate at end of period | $ | 0.7699 | $ | 0.7330 | ||||
| Average rate for the three month period | $ | 0.7576 | $ | 0.7575 | ||||
General Overview
Deep Well Oil & Gas, Inc., along with its subsidiaries through which it conducts business, is an independent junior oil sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base where we have working interests ranging from 25% to 100% in the Peace River oil sands area of Alberta, Canada. Our principal office is located at Suite 700, 10150 - 100 Street NW, Edmonton, Alberta, Canada T5J 0P6, our telephone number is (780) 409-8144, and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com. Our financial statements are available for download on our website or you may download our financial statements from the SEC’s website at www.sec.gov. The contents of our website are not part of this quarterly report on Form 10-Q.
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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, drilling, testing and analyzing of wells to define our oil sands reservoir, and development planning of our Alberta Energy Regulatory (“AER”) approved thermal recovery projects, which includes our joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) where we have a 25% working interest.
Our main objective is to develop our oil sands lease holdings located in the Peace River oil sands area of North Central Alberta, Canada (also known as our Sawn Lake oil sands properties) using thermal recovery technologies. Currently, we have received approval from the AER for two thermal recovery projects located on our Sawn Lake properties. To date, our geological, engineering, economic studies, and our SAGD Project production results lead us to believe that our working interest can support future full profitable commercial production.
A SAGD Project on our Sawn Lake properties commenced in 2013 where we have a 25% working interest. The SAGD Project consists of one SAGD well pair drilled to a depth of 650 meters and a horizontal length of 780 meters and the SAGD facility for steam generation, water handling, and bitumen treating. Steam injection commenced in May 2014 and production started in September of 2014. The SAGD Project reached a steady state production level in February of 2016 of 620 bopd, on a 100% basis (155 bopd net to us) from one SAGD well pair and achieved an instantaneous Steam oil Ratio (“ISOR”) efficiency of 2.1, demonstrating the productive capability of our Sawn Lake reservoir with significant future potential value. The lower the ISOR the lower the production costs and emissions per barrel of oil produced. A majority of our Company’s Joint Venture partners voted to temporarily suspend operations for the SAGD Project at the end of February 2016.
The SAGD Project has:
| ● | confirmed that the SAGD process works in the Bluesky formation at Sawn Lake; |
| ● | established characteristics of ramp up through stabilization of SAGD performance; |
| ● | indicated the productive capability and ISOR of the reservoir; and |
| ● | provided critical information required for well and facility design associated with future commercial development. |
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The production results of the SAGD Project successfully confirmed the capability of the Bluesky reservoir to produce using thermal recovery technology. The following graph sets out the production levels that the SAGD Project achieved. These production numbers compare favorably to analogous reservoirs in thermal recovery projects that we are monitoring and using as a basis of comparison.
In early May of 2016, an amended application was submitted to the AER for a commercial expansion of the existing SAGD Project facility site and received regulatory approval in December 2017. This expansion application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs will need to be operating to achieve this production level. The SAGD Project development plan will be done in stages to reduce initial financial costs. The first stage anticipates the reactivation of the existing SAGD facility and existing SAGD well pair, along with the drilling of one additional SAGD well pair, initially producing from two SAGD well pairs. The second stage anticipates drilling an additional three SAGD well pairs to produce up to 3,200 bopd and the expansion of the existing SAGD facility to generate the additional steam required. The lead time to acquiring the necessary equipment and commencing operations is estimated to be about 18 months and another 6 months is required for the start of bitumen production (after development of the steam chamber). We anticipate our near- and long-term funding of our operations to be financed through the existing Farmout Agreement, future earn-in agreements, and cash flow from the reactivation of the existing SAGD Project. We also intend to negotiate with the Petroleum and Natural Gas holders in the area of our leases, to enter into further downhole contribution agreements to acquire additional logs and cores of the Bluesky formation, in order to expand the boundaries of the oil sands reservoir we have already defined and save on drilling costs and reduce our environmental footprint. We and our joint venture partners continue to move forward with SAGD Project with completing detailed engineering and assessing potential marketing arrangements for the commercial development expansion to 3,200 bopd (100% basis). As of June 30, 2019, a Sawn Lake full field development plan using SAGD batteries has been defined by the operator of the SAGD Project.
On February 15, 2018, we entered into a contribution agreement with a third-party, whereby we paid a cash contribution to drill and acquire cores and logs through the Bluesky formation from a well drilled by a third-party on one of our oil sands leases.
We previously received approval from the AER for a 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 at least a 90% working interest. The final performance results and revised reservoir modeling studies from our SAGD Project will be used to fine-tune our HCSS Project facility design before we initiate start-up operations on the half of a section of land where we plan to drill two horizontal wells to test the use of HCSS technology. We performed an environmental field study and surveyed the proposed location of our planned HCSS Project site and received AER approval for the surface wellsite and access road for this HCSS Project.
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Our Company to date has, but not limited to, drilled or participated in 13 wells over our Sawn Lake leases to expand the boundaries of the Bluesky oil sands reservoir; commissioned various independent reservoir simulation studies of our properties; successfully produced bitumen from the SAGD Project, which outperformed independent reservoir production type curves; acquired AER approval for two thermal recovery projects, which includes our joint SAGD Project facility expansion to produce up to 3200 bopd; successfully entered into Farmout Agreements; and we have successfully applied to the AER to continue the best sections of our oil sands properties past their initial lease expiry dates, where resources were identified. Under the oil sands lease continuation regulations an operator or leaseholder must demonstrate certain levels of exploration and development by providing the AER with drilling, coring and seismic data within a certain timeframe in order to maintain the lease past its expiry date. Our Company’s Sawn Lake oil sands properties under lease as of September 30, 2019, covers 19,610 gross acres (13,442 net acres) of land under seven oil sands leases. The lease expiration dates of our Company’s oil sands leases are as follows:
| 1. | Out of 20,242 gross acres (13,284 net acres) under five oil sands leases were set to expiry on July 10, 2018, 14,549 gross acres (8,571 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. In November of 2017, our Company’s joint venture partner and operator of two of these five oil sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591 gross acres (1,898 net acres) and in January 2018, approval was received from Alberta Energy to continue 6,958 gross acres (1,740 net acres). In June 2018, our Company as operator of three of these five oil sands leases, submitted three continuation applications to the Alberta Oil Sands Tenure division to apply to continue another 7,591 gross acres (6,832 net acres) where resources were identified and in July 2018 and April 2019, approval was received from Alberta Energy to continue 7,591 gross acres (6,832 net acres). Of these five oil sands leases that were set to expiry on July 10, 2018, a total of 5,693 gross acres (4,713 net acres) expired without being continued. These expired lands were primarily areas where our Company determined that there was no or limited exploitable resources. These continued leases are now held by our Company for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases. |
| 2. | 19,610 gross acres (17,649 net acres) under the three most northern oil sands leases were set to expire on August 19, 2019. In August 2019, our Company submitted one continuation application to the Alberta Oil Sands Tenure division to apply to continue 1,898 acres (1,708 net acres) of the 19,610 gross acres (17,649 net acres) on one of the northern most leases and subsequently in early October 2019 approval was received from Alberta Energy to continue 1,898 gross acres (1,708 net acres) past the expiry date of the lease. This one partially continued lease is now held by our Company for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases. On August 19, 2019, 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where we determined that there was no or limited exploitable resources. |
| 3. | 3,163 gross acres (3,163 net acres) under one oil sands lease are set to expire on April 9, 2024. It is our Company’s opinion that we have already met the governmental requirements for this lease, and we will be applying to continue this lease into perpetuity. |
The development progress of our Sawn Lake oil sands 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 and our projects. Because of these and other factors, our oil sands projects can take significantly longer to complete than regular conventional drilling programs for lighter oil.
Results of Operations
The following table sets forth summarized financial information:
| Three Months Ended | Three Months Ended | |||||||
| December 31, 2019 | December 31, 2018 | |||||||
| Revenue | $ | – | $ | – | ||||
| Provincial royalty expenses | – | – | ||||||
| Revenue, net of royalty | – | – | ||||||
| Expenses | ||||||||
| Operating expenses | 27,738 | 39,660 | ||||||
| Operating expense covered by Farmout | (27,738 | ) | (39,660 | ) | ||||
| General and administrative | 30,321 | 53,855 | ||||||
| Depreciation, accretion and depletion | 10,843 | 11,442 | ||||||
| Net loss from operations | (41,164 | ) | (65,297 | ) | ||||
| Other income and expenses | ||||||||
| Rental and other income | (2,047 | ) | 2,046 | |||||
| Interest income | 1,994 | 1,810 | ||||||
| Net loss | $ | (41,217 | ) | $ | (61,441 | ) | ||
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There was no production volumes or revenues for the years ending December 31, 2019 and 2018, due to a majority of our Company’s Joint Venture partners voting to temporarily suspend operations of the SAGD Project at the end of February 2016. In accordance with the Farmout Agreement we entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project in return for a net 25% working interest in two oil sands leases where we had a working interest of 50% before the execution of the Farmout Agreement. Under the terms of the Farmout Agreement the Farmee is required to provide funding to cover the monthly administrative expenses of our Company provided that such funding shall not exceed $30,000 per month. The Farmee shall continue to cover our Company’s administrative costs up to $30,000 per month until completion in all substantial respects of the SAGD Project agreement entered into between the Company and the operator of the SAGD Project. Our net operating margin after operating expenses is zero, under the Farmout Agreement, any negative operating cash flows are reimbursed to us to fund our share of the SAGD Project. Therefore, the total share of the capital costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, as of December 31, 2019, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $21.1 million (Cdn$27.4 million) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project. These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator, production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the one SAGD well pair when the facility was producing; and the expenses associated the monthly shut-in operations of the SAGD Project facility.
For the three months ended December 31, 2019, our general and administrative expenses decreased by $23,534 compared to the three months ended December 31, 2018, which was primarily due to decreases in office rent and auditor fees. We received $90,000 during this quarter from the Farmee in accordance with a Farmout Agreement to offset some of our monthly expenses. After adjusting out the non-cash item for foreign exchange and the funds we received from the Farmee, our general and administrative expenses were $119,643 for the three months ended December 31, 2019 compared to $146,732 for the three months ended December 31, 2018.
For the three months ended December 31, 2019, our depreciation, depletion, and accretion expense decreased by $599 compared to the three months ended December 31, 2018, 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 December 31, 2019.
For the three months ended December 31, 2019, there was $4,093 decrease for rental and other income compared to the three months ended December 31, 2018.
As a result of the above transactions, we recorded a decrease of $20,224 in our net loss for the three months ended December 31, 2019 compared to the three months ended December 31, 2018. As discussed above, this decrease was primarily due to decreases in office rent fees and audit fees.
Liquidity and Capital Resources
As of December 31, 2019, our total assets were $22,672,085 compared to $22,677,977 as of September 30, 2019.
Our total liabilities as of December 31, 2019 were $606,709 compared to $571,384 as of September 30, 2019. There was no significant change in our total liabilities from the September 30, 2019 year end.
Our working capital (current liabilities subtracted from current assets) is as follows:
| Three months Ended | Year Ended | |||||||
| December 31, 2019 | September 30, 2019 | |||||||
| Current Assets | $ | 147,497 | $ | 167,379 | ||||
| Current Liabilities | 91,739 | 70,992 | ||||||
| Working Capital | $ | 55,758 | $ | 96,387 | ||||
As of December 31, 2019, we had working capital of $55,758 compared to a working capital of $96,387 as of September 30, 2019. This decrease of $40,629 is primarily due to cash used for general and administrative expenses.
As reported on our condensed Consolidated Statement of Cash Flows under “Operating Activities”, for the three months ended December 31, 2019, our net cash used in operating activities was $1,754 compared to $81,855 for the three months ended December 31, 2018. This decrease of $80,101 in our operating activities was due to a decrease of $20,224 for general and administrative expenses and a decrease of $60,476 from changes in non-cash working capital.
As reported on our condensed Consolidated Statement of Cash Flows under “Investing Activities”, we had a decrease of $38,632 on investment in our oil and gas properties for the three months ended December 31, 2019, compared to the three months ended December 31, 2018. There were no significant investing activities during these periods.
As reported on our condensed Consolidated Statement of Cash Flows under “Financing Activities”, for the three months ended December 31, 2019 and December 31, 2018, we had a decrease of $15,000 compared to the three months ended December 31, 2018. There were no financing activities for the three months ended December 31, 2019 period.
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Our cash and cash equivalents as of December 31, 2019 was $37,706 compared to $181,691 as of December 31, 2018. This decrease of $143,985 in cash was primarily due to the cash used in general and administrative expenses.
As of December 31, 2019, we had no long-term debt other than our estimated future asset retirement obligations on oil and gas properties.
Our current SAGD Project capital and operating costs are covered under the terms of the Farmout Agreement. In addition, as described above the Farmee shall continue to cover our administrative costs up to $30,000 per month, under the Farmout Agreement, until completion in all substantial respects of the SAGD Demonstration Project agreement entered into between us and the operator of the SAGD Project. 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, debt, or entering into another form of joint venture. 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
There is no transaction, arrangement, or other relationship between our Company or any of our subsidiaries and an unconsolidated or affiliated entity that is not reflected on our Company’s Financial Statements that is required to be disclosed by our Company in our SEC filings and is not already disclosed.
Cautionary Note Regarding Forward-Looking Statements
This quarterly report on Form 10-Q, including all referenced Exhibits, contains “forward-looking statements” within the meaning of the United States federal securities laws. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, projected costs and plans and objectives of management for future operations, are forward-looking statements. The words “may,” “believe,” “intend,” “will,” “anticipate,” “expect,” “estimate,” “project,” “future,” “plan,” “strategy,” “probable,” “possible,” or “continue,” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters, often identify forward-looking statements. For these statements, Deep Well claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The forward-looking statements in this quarterly report include, among others, statements with respect to:
| ● | our current business strategy; |
| ● | our future financial position and projected costs; |
| ● | our projected sources and uses of cash; |
| ● | our plan for future development and operations, including the building of all-weather roads; |
| ● | our drilling and testing plans; |
| ● | our proposed plans for further thermal in-situ development or demonstration project or projects; |
| ● | the sufficiency of our capital in order to execute our business plan; |
| ● | our reserves and resources estimates; |
| ● | the timing and sources of our future funding; |
| ● | the quantity and value of our reserves; |
| ● | the intent to issue a distribution to our shareholders; |
| ● | our or our operator’s objectives and plans for our current SAGD Project; |
| ● | our plans for development of our Sawn Lake properties; |
| ● | production levels from our current SAGD Project; |
| ● | costs of our current SAGD Project; |
| ● | funding from the Farmee to pay our costs for the current SAGD Project in connection with the Farmout Agreement; |
| ● | additional sources of funding from the Farmout Agreement; |
| ● | funding from the Farmee to cover our monthly operating expenses; |
| ● | our access and availability to third-party infrastructure; |
| ● | present and future production of our properties; |
| ● | our ability to extend our remaining lease; past its primary expiration date; and |
| ● | expectations regarding the ability of our Company and its subsidiaries to raise capital and to continually add to reserves through acquisitions and development. |
These forward-looking statements are based on the beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations and projections. Factors that could cause actual results to differ materially from those set forward in the forward-looking statements include, but are not limited to:
| ● | changes in general business or economic conditions; |
| ● | changes in governmental legislation or regulation that affect our business; |
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| ● | our ability to obtain necessary regulatory approvals and permits for the development of our properties, including obtaining the required water licenses from Alberta Environment to withdraw water for our thermal operations; |
| ● | changes to the greenhouse gas reduction program and other environmental and climate change regulations which are adopted by provincial or federal governments of Canada or which are being considered, which may also include cap and trade regimes, carbon taxes, increased efficiency standards, each of which could increase compliance costs and impose significant penalties for non-compliance; |
| ● | increase in taxes and changes to existing legislation affecting governmental royalties or other governmental initiatives; |
| ● | future marketing and transportation of our produced bitumen; |
| ● | our ability to receive approvals from the AER for additional tests to further evaluate the wells on our lands; |
| ● | our Farmout Agreement and joint operating agreements; |
| ● | opposition to our regulatory requests by various third parties; |
| ● | actions of aboriginals, environmental activists and other industrial disturbances; |
| ● | the costs of environmental reclamation of our lands; |
| ● | availability of labor or materials or increases in their costs; |
| ● | the availability of sufficient capital to finance our business or development plans on terms satisfactory to us; |
| ● | adverse weather conditions and natural disasters affecting access to our properties and well sites; |
| ● | risks associated with increased insurance costs or unavailability of adequate coverage; |
| ● | volatility in market prices for oil, bitumen, natural gas, diluent and natural gas liquids. A decline in oil prices could result in a downward revision of our future reserves and a ceiling test write-down of the carrying value of our oil sands properties, which could be substantial and could negatively impact our future net income and shareholders’ equity; |
| ● | competition; |
| ● | changes in labor, equipment and capital costs; |
| ● | future acquisitions or strategic partnerships; |
| ● | the risks and costs inherent in litigation; |
| ● | imprecision in estimates of reserves, resources and recoverable quantities of oil, bitumen and natural gas; |
| ● | product supply and demand; |
| ● | changes and amendments in the Canadian Oil and Gas Evaluation Handbook and or the Petroleum Resources Management System to general disclosure of reserves and resources standards and specific annual reserves and resources disclosure requirements for reporting issuers with oil and gas activities; |
| ● | future appraisal of potential bitumen, oil and gas properties may involve unprofitable efforts; |
| ● | the ability to meet minimum level of requirements and obtain approval from the AER to continue our remaining oil sands lease beyond its expiry date; |
| ● | the ability to pay future escalating oil sands lease rents on our continued leases; |
| ● | our ability to meet the minimum level of production requirements on our oil sands leases as set out by the AER in order to eliminate future escalating oil sands lease rents on our continued leases; |
| ● | 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, 2019 filed with the SEC and the ASC on SEDAR on January 13, 2020.. 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.
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| 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 December 31, 2019, 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 December 31, 2019, 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.
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| ITEM 1. | LEGAL PROCEEDINGS |
On October 28, 2019, Provident Premier Master Fund Ltd. (the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”) in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim was filed on November 1, 2018 but our Company was never served so we were not aware of it.
The Plaintiff claims that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all petroleum substances produced, saved and marketed from six of our Company's oil sands leases located within our Company's Sawn Lake properties.
The Plaintiff seeks: 1) A declaration that the Plaintiff is the legal owner of 0.67% of the GORR payable on all oil sands produced from the lands which is payable by one or more of the Defendants; 2) An accounting to determine the amount of the outstanding royalty of which judgment is estimated by the Plaintiff to be in the amount of $100,000 Cdn; and 3) Interest and costs.
We continue to deny the validity of the Purported 6.5% Royalty in the first instance. As well, if the Purported 6.5% Royalty was valid, which is denied, it was not a gross overriding interest, but rather an overriding interest, which allowed for the deduction of operating and marketing costs. We plan to vigorously defend against the Plaintiff’s claims.
| ITEM 1A. | RISK FACTORS |
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, 2019, filed with the Alberta Securities Commission on SEDAR on January 13, 2020 and the U.S. Securities and Exchange Commission on January 13, 2020.
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| 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 for the period ended December 31, 2019.
Shareholder Nominations
There have been no changes to the procedures by which shareholders may recommend nominees to our Board of Directors during the time period covered by this quarterly report on Form 10-Q for the period ended December 31, 2019.
| ITEM 6. | EXHIBITS |
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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 | February 19, 2020 | |
| By | /s/ Curtis J. Sparrow | |
| Mr. Curtis James Sparrow | ||
| Chief Financial Officer | ||
| (Principal Financial and Accounting Officer) | ||
| Date | February 19, 2020 | |
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