UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 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, Edmonton, Alberta, Canada | T5J 0P6 | |
| (Address of principal executive offices) | (Zip Code) | |
Registrant’s telephone number, including area code: (780) 409-8144
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 |
Securities registered pursuant to Section 12(g) of the Act:
| Common Stock, $0.001 par value per share |
| (Title of class) |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Sections 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 such 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 Act). Yes ☐ No þ
The aggregate market value of the registrant’s common stock held by non-affiliates computed by reference to the price at which the common equity was sold on or about March 31, 2019 was approximately $2.9 million.
As of January 13, 2020, the Issuer had outstanding approximately 230,574,603 shares of common stock, $0.001 par value per share.
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The following are defined terms and abbreviations used herein:
API Gravity – a specific gravity scale developed by the American Petroleum Institute for measuring the density or specific gravity (heaviness) of petroleum liquids, expressed in degrees. The higher the number, the lighter the oil.
Alberta Energy Regulator (“AER” formerly “ERCB”) – The AER is responsible for the development of Alberta’s oil (including oil sands) and gas resources. The AER succeeded the Energy Resources Conservation Board (“ERCB”) and will take on regulatory functions from the Ministry of Environment and Sustainable Resource Development that relate to public lands, water, and the environment. The AER will provide full-lifecycle regulatory oversight of energy resource development in Alberta from application and construction to abandonment and reclamation, and everything in between.
Barrel – the common unit for measuring petroleum, including heavy oil. One barrel contains approximately 159 L.
Battery – equipment to process or store crude oil from one or more wells.
Bbl or Bbls – means barrel or barrels.
Bitumen – a heavy, viscous form of crude oil that generally has an API gravity of less than 10 degrees.
Cdn$ or Cdn dollar – means Canadian dollars.
Celsius – a temperature scale that registers the freezing point of water as 0 degrees and the boiling point as 100 degrees under normal atmospheric pressure. Room temperature is between 20 degrees and 25 degrees Celsius. Temperatures specified herein are quoted in degrees Celsius unless indicated otherwise.
Cold Flow – a production technique where the oil is simply pumped out of the sands not using a Thermal Recovery Technique.
Conventional Crude Oil – crude oil that flows naturally or that can be pumped without being heated or diluted.
Core – a cylindrical rock sample taken from a formation for geological analysis.
Crude Oil – oil that has not undergone any refining. Crude oil is a mixture of hydrocarbons with small quantities of other chemicals such as sulphur, nitrogen and oxygen. Crude oil varies radically in its properties, namely specific gravity and viscosity.
Cyclic Steam Stimulation (“CSS”) or Horizontal Cyclic Steam Stimulation (“HCSS”) – a thermal in situ recovery method, which consists of a three-stage process involving high-pressure steam injected into the formation for several weeks through vertical or horizontal wells. The heat softens the oil while the water vapor helps to dilute and separate the oil from the sand grains. The pressure also creates channels through which the oil can flow more easily to the well. When a portion of the reservoir is thoroughly saturated, the steam is turned off and the reservoir maybe left to “soak” a short period of time. This is followed by the production phase, when the oil flows, or is pumped, up the same wells to the surface. When production rates decline, another cycle of steam injection begins. This process is sometimes called “huff-and-puff” recovery and can be done utilizing vertical or horizontal wells.
Darcy (Darcies) – a measure of rock permeability (the degree to which natural gas or crude oil can move through the rocks).
Density – the heaviness of crude oil, indicating the proportion of large, carbon-rich molecules, generally measured in kilograms per cubic metre (“kg/m3”) or degrees on the American Petroleum Institute (“API”) scale.
Development Well – a well drilled within an area of a natural gas or oil reservoir to the depth of a stratigraphic horizon to which proven reserves have been assigned.
Diluents – light petroleum liquids used to dilute bitumen and heavy oil so they can flow through pipelines.
Drill Stem Test (“DST”) – a method of formation testing. The basic drill stem test tool consists of a packer or packers, valves or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on the drill string to the zone to be tested. The packer or packers are set to isolate and test the zone from the drilling fluid column.
Drill String – the column, or string, of drill pipe with attached tool joints that transmits fluid and rotational power from the drilling rig on the surface to the drill collars and the bit. Often, the term is loosely applied to include both drill pipe and drill collars.
Enhanced Oil Recovery – any method that increases oil production by using techniques or materials that are not part of normal pressure maintenance or water flooding operations. For example, natural gas can be injected into a reservoir to “enhance” or increase oil production.
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Exploratory Well – a well drilled to find and produce natural gas or oil in an unproven area, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir, or to extend a known reservoir.
Farmout – an arrangement whereby the owner of a lease assigns some ownership portion (or all) of the lease(s) to another company (the “Farmee”) in return for the Farmee paying for the drilling on at least some portion of the lease(s) under the Farmout.
Gross Acre/Hectare – a gross acre is an acre in which any portion of a working interest is owned. 1 acre = 0.4046 hectares. 1 hectare = 2.471 acres.
Heavy Oil – oil having an API gravity less than 22.3 degrees.
Horizontal Well – the drilling of a well that deviates from the vertical and travels horizontally through a producing layer of a reservoir.
In-situ – in the oil sands context (in-situ means “in place” in Latin), in-situ methods such as SAGD or CSS through horizontal or vertical wells maybe required to produce the oil if the oil sands deposits are too deep to mine from the surface.
Lease – a legal document giving an operator the right to drill for or produce oil or gas; also, the land on which a lease has been obtained.
License of Occupation (“LOC”) – a surface crown agreement issued by the Alberta Department of Sustainable Resources Development granting the mineral producer the right to occupy public lands for an approved purpose, usually issued primarily for access roads or to construct access roads but may also be issued for other purposes.
Light Crude Oil – liquid petroleum which has a low density and flows freely at room temperature. Also called conventional oil, it has an API gravity of at least 22 degrees and a viscosity less than 100 centipoise.
Mbbl or Mbbls – means one thousand barrels or thousands of barrels.
MMbbl or MMbbls – means one million barrels or millions of barrels.
Mmcf – means million cubic feet.
Mineral Surface Lease (“MSL”) – a surface crown agreement issued by the Alberta Department of Sustainable Resources Development granting the mineral producer the right to construct a well site on publicly owned land.
Net Acre/Hectare – a net acre is the result that is obtained when the fractional ownership working interest of a lease is multiplied by gross acres of that lease.
Oil Sands – naturally occurring mixtures of bitumen, water, sand and clay that are found mainly in three areas of Alberta - Athabasca, Peace River and Cold Lake. A typical sample of oil sand might contain about 12% bitumen by weight.
Pay Zone (Net Oil Pay) – the producing part of a formation.
Permeability – the capacity of a reservoir rock to transmit fluids; or how easily fluids can pass through a rock. The unit of measurement is the darcy or millidarcy.
Porosity – the capacity of a reservoir to store fluids, the volume of the pore space within a reservoir, measured as a percentage.
Possible Reserves * – additional unproved reserves that analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves but have at least a ten percent probability of being recovered.
Primary Recovery – the production of oil and gas from reservoirs using the natural energy available in the reservoirs and pumping techniques.
Proved Developed Reserves * – are those reserves that can be expected to be recovered.
Probable Reserves * – additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
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Proved Reserves * – estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved Undeveloped Reserves * – are those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Saturation – the relative amount of water, oil, and gas in the pores of a rock, usually as a percentage of volume.
SEC – means United States Securities and Exchange Commission.
Section – in reference to a parcel of land, meaning an area of land comprising approximately 640 acres.
Service Well – a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.
Solution Gas – natural gas that is found “in solution” within crude oil in underground reservoirs. When the oil comes to the surface, the gas expands and comes out of the solution.
Specific Gravity – the ratio of the heaviness of a substance compared to that of the same volume of water.
Steam-Assisted Gravity Drainage (“SAGD”) – pairs of horizontal wells (an upper well and a lower well) are drilled into an oil sands formation and steam is injected continuously into the upper well. As the steam heats the oil sands formation, the bitumen softens and drains into the lower well, from which it is brought to the surface.
Steam to Oil Ratio (“SOR”) – measures the number of barrels of steam (measured in “Cold Water Equivalent Barrels”) needed for every barrel of oil produced.
Thermal Recovery – a type of improved recovery in which heat is introduced into a reservoir to lower the viscosity of heavy oils and to facilitate their flow into producing wells. The pay zone may be heated by injecting steam (steam drive) or by injecting air and burning a portion of the oil in place (in situ combustion).
Upgrading – the process that converts bitumen and heavy oil into a product with a density and viscosity similar to conventional light crude oil.
US$, USD, or US dollar - means United States dollars.
Viscosity – a measure of a fluid’s resistance to flow. To simplify, the oil’s viscosity represents the measure for which the oil wants to stay put when pushed by moving mechanical components. It varies greatly with temperature. The more viscous the oil the greater the resistance and the less easy it is for it to flow. Centipoise is the common unit for expressing absolute viscosity. Viscosity matters to producers because the oil’s viscosity at reservoir temperature determines how easily oil flows to the well for extraction.
* This definition is an abbreviated version of the complete definition as defined by the SEC under Rule 4-10(a) of Regulation S-X.
Our functional currency is the US dollar. Therefore, our accounts are reported in United States dollars. However, our Canadian subsidiaries maintain their accounts and records in Canadian dollars. As a result, the Canadian dollar amounts are converted according to our stated foreign currency translation accounting policy, except where otherwise indicated, all dollar amounts herein are stated in US dollars.
The following table sets forth the rates of exchange for the Canadian dollar, expressed in US dollars, in effect at the end of the following periods and the average rates of exchange during such periods, as reported by the Bank of Canada.
| Year ending September 30 | 2019 | 2018 | ||||||
| Rate at year end | $ | 0.7551 | $ | 0.7725 | ||||
| Average rate for year | $ | 0.7537 | $ | 0.7793 | ||||
Unless the context indicates another meaning, the terms “Company,” “Deep Well,” “we,” “us” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries through which it conducts business. For definitions of some terms used throughout this report, see “Glossary and Abbreviations”.
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| ITEM 1. | BUSINESS |
We are 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 in the Peace River oil sands area of Alberta. Our principal office is located at Suite 700, 10150 – 100 Street NW, Edmonton, Alberta 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 our common stock trades on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com. The contents of our website are not part of this annual report on Form 10-K for the fiscal year ended September 30, 2019 (this “Annual Report”).
Formation of Organization
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. 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 Oil & Gas, Inc. has two wholly owned subsidiaries through which it conducts its operations: (1) Northern Alberta Oil Ltd. (“Northern”) acquired on June 7, 2005, and incorporated under the Business Corporations Act (Alberta), Canada on September 18, 2003; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005.
Business Development
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 Alberta Energy Regulator (“AER”) for two thermal recovery projects located on our Sawn Lake properties.
Over the last 3 years we have successfully applied to the AER to continue the best sections of our oil sands properties past their initial 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. For more information regarding our oil sands properties see “Oil and Gas Properties” under Item 2 “Properties” of this Annual Report on Form 10-K.
In late July of 2013 we entered into a Steam Assisted Gravity Drainage Demonstration Project Joint Operating Agreement (the “SAGD Project”) where we have a 25% working interest with one joint venture partner. In late July of 2013 we entered into a farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”). The SAGD Project produced bitumen for 18 months, demonstrating the productive capability of our Sawn Lake reservoir. In 2016 a majority of our Company’s Joint Venture partners voted to temporarily suspend operations for the SAGD Project. In early May of 2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would potentially increase the operations up to a total of eight SAGD well pairs. The amended application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). Regulatory approval was received in December 2017 for a commercial expansion of the existing SAGD Project facility site where we have a 25% working interest. It is anticipated that only five SAGD well pairs will be needed to achieve the 3,200 bopd production level. For more information regarding our SAGD Project and our Farmout Agreement, see “Present Activities - Peace River Oil Sands, Alberta Canada (Sawn Lake Properties)” under Item 2 “Properties” of this Annual Report on Form 10-K.
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Principal Product
We are engaged in the identification, acquisition, exploration and development of oil sands prospects. Exploration and development for commercially viable production of any oil sands company includes a high degree of risk, which careful evaluation, experience and factual knowledge may not eliminate.
Sawn Lake Oil Sands Properties – Peace River Oil Sands, Alberta, Canada
Currently, we have working interests in seven oil sands leases ranging from 25% to 100% in the Peace River oil sands area of Alberta, where we are the operator of five leases. The focus of our Company’s operations is to develop the oil sands reservoir to establish proven reserves and to determine the best technology under which the oil can be produced from our Sawn Lake properties in order to generate positive cash flow. For further information on our oil sands projects see Item 2 “Oil and Gas Properties” in this Annual Report on Form 10-K.
Market and Distribution of Product
On lands where we have a 25% working interest, the operator of the SAGD Project markets and distributes all oil produced from the SAGD Project facility. Production from the SAGD Project was trucked and sold to marketing facilities in the Peace River area of Alberta. A majority of the Joint Venture partners voted to temporarily suspend operations for the SAGD Project at the end of February 2016.
On lands where we are the operator, we intend to sell our oil production under both short-term (less than one year) and long-term (one year or more) agreements at prices negotiated with third parties. Under both short-term and long-term contracts, typically either the entire contract (in the case of short-term contracts) or the price provisions of the contract (in the case of long-term contracts) are renegotiated in intervals ranging in frequency from daily to annual. At this time, we have no production on any of the lands where we are the operator and therefore, we have no short-term or long-term contracts. We will adopt specific sales and marketing plans once production is achieved on lands where we are designated as the operator. The operator of our joint SAGD Project marketed and distributed all oil produced from our joint SAGD Project.
Market pricing for bitumen is seasonal, with lower prices in and around the calendar year-end being the norm due to lower demand for asphalt and other bitumen-derived products. By necessity, bitumen is regularly blended with diluent in order to facilitate its transportation through pipelines to North American markets. As such, the effective field price for bitumen is also directly impacted by the input cost of the diluent required, the demand and price of which is also seasonal in nature (higher in winter as colder temperatures necessitate more diluent for transportation). Consequently, bitumen pricing is usually weakest in and around December and not reflective of the annual average realized price or the economics of the “business” overall. We have been advised that, to price bitumen, marketers apply formulas that take as a reference point the prices published for crude oil of particular qualities such as “Western Canadian Select”, “Brent Crude Oil”, “Crude Bitumen 9 API Plant Gate”, “Edmonton Light”, “Lloydminster Blend”, or the more internationally known “West Texas Intermediate” (“WTI”).
Competitive Business Conditions
We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties as well as for the equipment, labour and materials required to develop and operate those properties. Many of our competitors have longer operating histories and substantially greater financial and other resources. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage, whereas we may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Larger competitors may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices of gas and oil more easily. Our competitors may also be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.
Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of Canada and other countries as well as other factors beyond our control, including international political stability, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources.
Customers
The operator of our SAGD Project, distributed and sold all of the oil that was produced from the SAGD Project. Production was sold to 11 different marketing facilities in Alberta.
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Royalty Agreements
Through the acquisition of Northern, we potentially became a party to the following:
On December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a purported royalty agreement with Mikwec Energy Canada, Ltd. (now known as Northern) that potentially encumbers six of our oil sands leases located within our Sawn Lake properties (the “Purported 6.5% Royalty”). Nearshore claimed to have received the Purported 6.5% Royalty from Northern on the leased substances on the land interests which Northern holds in the above six oil sands leases. Nearshore was a private corporation incorporated in Alberta, Canada, and was owned and controlled by Mr. Steven P. Gawne and his wife, Mrs. Rebekah J. Gawne, who each owned 50% of Nearshore. Mr. Steven P. Gawne was the President, Chief Executive Officer and a director of Deep Well from February 6, 2004 to June 29, 2005. Nearshore has subsequently transferred part or all of the Purported 6.5% Royalty to other parties. 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 most of the Purported 6.5% Royalty to prevent a potential encumbrance over our land and the possibility of future litigation resulting from these alleged royalty claims. In our fiscal year 2014, we acquired 5.5% of the Purported 6.5 % Royalty for a cost of $3.4 million. See Item 3 Legal Proceedings in this annual report on Form 10-K.
Government Approval and Crown Royalties
Exploration and Production. Our operations are subject to Canadian federal and provincial governmental regulations. Such regulations include: requiring approval and licenses for the drilling of wells, regulating the location of wells and the method and ability to produce the wells, surface usage and the restoration of land upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from our wells. Our operations are also subject to various conservation regulations, including the regulation of in-situ recovery processes, the size of spacing units, the number of wells which may be drilled in a unit, the unitization or pooling of oil and gas properties, the rate of production allowable from oil and gas wells and the ability to produce oil and gas.
Investment Canada Act. The Investment Canada Act of 1985, as amended, requires notification and/or review by the government of Canada in certain cases, including but not limited to, the acquisition of control, directly or indirectly, of a Canadian Business by a non-Canadian. In certain circumstances, the acquisition of a working interest in a property that contains recoverable reserves will be treated as the acquisition of an interest in a “business” and may be subject to either notification or review, depending on the size of the interest being acquired and the asset size of the business.
Crown Royalties and Incentives. Crown royalties are determined by provincial and federal government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada and Alberta have established incentive programs such as royalty rate reductions, royalty holidays, tax credits and drilling royalty credits. These incentives are for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally increase cash flow. Oil sands royalties in Alberta are calculated using a sliding scale for royalty rates ranging from 1% to 9% pre-payout and 25% to 40% post-payout depending on the world oil price. Project “payout” refers to the point in which we earn sufficient revenues to recover all of the allowed costs for the project plus a return allowance. The base royalty starts at 1% and increases for every dollar the world oil price, as reflected by the WTI, is priced above $55 per barrel, to a maximum of 9% when oil is priced at $120 per barrel or greater. The net royalty starts at 25% and increases for every dollar oil is priced above $55 per barrel to 40% when oil is priced at $120 or higher.
Environmental Laws and Regulations
The oil and natural gas industry is subject to environmental laws and regulations pursuant to Canadian local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with oil and gas industry operations. Legislation requires that well and facility sites be monitored, abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages as well as administrative, civil and criminal penalties. Accordingly, we could be liable or could be required to cease production on properties if environmental damage occurs. Although we maintain insurance coverage, the costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur that result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations. We maintain commercial property and general liability insurance coverage on the properties we operate. We also maintain operators extra expense insurance which provides coverage for well control incidents specifically relating to regaining control of a well, seepage, pollution, clean-up and containment. No coverage is maintained with respect to any fine or penalty required to be paid due to a violation of the regulations set out by the federal and provincial regulatory authorities. We are committed to meeting our responsibilities to protect the environment and anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment.
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Employees
Our Company currently has two prime subcontractors and three full-time employees. For further information on our subcontractors see “Compensation Arrangements for Executive Officers” under Item 11 “Executive Compensation” of this Annual Report on Form 10-K. We expect that, from time to time, we will hire more employees, independent consultants and contractors during the stages of implementing our plans.
| ITEM 1A. | RISK FACTORS |
An investment in our common stock is speculative and involves a high degree of risk and uncertainty. You should carefully consider the risks described below, together with the other information contained in our reports filed with the U.S. Securities and Exchange Commission (“SEC”), including the consolidated financial statements and notes thereto of our Company before deciding to invest in our common stock. The risks described below are not the only ones facing our Company. Additional risks not presently known to us, or that we presently consider immaterial may also adversely affect our Company. If any of the following risks occur, our business, financial condition and results of operations and the value of our common stock could be materially and adversely affected.
Any Development Of Our Resources Will Be Subject To Royalties. The royalty regime of Alberta is a significant factor in the profitability of oil and natural gas production in Alberta, Canada. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. Penalties and interest may be charged to us if we fail to remit royalties on our production to the Crown as prescribed in the regulation. In addition, there is a risk that the remaining 1% of the Purported 6.5% Royalty could be found to be valid.
We Have A History Of Losses And May Not Achieve Or Sustain Profitability In The Future. Since our inception, we have suffered recurring losses from operations and have been dependent on new investment to sustain our operations. During the years ended September 30, 2019 and 2018 we reported net losses of $197,135 and $330,131 respectively. We may not achieve profitability in the foreseeable future, if at all. In addition, our operating expenses may be more than our future revenue growth. We expect our future cost of revenue and operating expenses to continue to increase in the foreseeable future as we continue to expand on our thermal recovery operations at Sawn Lake, Alberta.
Future Price Declines May Result In A Write-Down Of Asset Carrying Values. Effective July 1, 2015, our Company adopted the full-cost method of accounting for costs related to our oil sands properties. Under the full cost method, oil and gas properties are subject to a 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 cost centre ceiling is the sum of: (i) present value of the estimated future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor; (ii) the costs of unproved properties not being amortized; (iii) the lower of cost or fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. During the 2019 and 2018 fiscal year, no ceiling test write-downs were recorded for our oil and gas properties. Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired are included in the costs subject to depletion within the full cost pool. A significant decline in oil prices from current levels, or other factors, without other mitigating circumstances, could cause a future write-down of our capitalized costs and a non-cash charge on our income statement.
The Successful Implementation Of Our Business Plan Is Subject To Risks Inherent In The Oil Sands Business. Our oil sands operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties, to drill exploratory wells and to produce bitumen using thermal recovery technologies. In addition, the cost and timing of drilling, completing, operating and acquiring regulatory approval for thermal recovery operations on our wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If our efforts are unsuccessful in establishing proven reserves, the amounts capitalized as unproven costs may be written down and charged against earnings. Our exploitation and development of oil sands reserves depends upon access to the areas where our operations are to be conducted. We conduct a portion of our operations in regions where we are only able to do so on a seasonal basis. Unless the surface is sufficiently frozen, we are unable to access our properties, drill or otherwise conduct our operations as planned. In addition, if the surface thaws earlier than expected, we must cease our operations for the season earlier than planned. Our operations are affected by road bans imposed from time to time during the break-up and thaw period in the spring. Road bans are also imposed due to heavy rain, mud, rock slides and periods of high water, which can restrict access to our well sites and potential production facility sites. Our inability to access our properties or to conduct our operations as planned would result in a shutdown or slowdown of our operations, which would adversely affect our business.
We Rely On Independent Experts And Technical Or Operational Service Providers Over Whom We May Have Limited Control. The success of our business is dependent upon the efforts of various third parties that we do not control. We rely upon various companies to assist us in identifying desirable oil prospects to acquire and to provide us with technical assistance and services. We also rely upon the services of geologists, geophysicists, chemists, engineers and other scientists to explore and analyze oil prospects to determine a method in which the oil prospects may be developed in a cost-effective manner. In addition, we rely upon the owners and operators of oil drilling equipment to drill and develop our prospects to production. Although we have developed relationships with a number of third-party service providers, we cannot assure that we will be able to continue to rely on such persons. If any of these relationships with third-party service providers are terminated or are unavailable on commercially acceptable terms, we may not be able to execute our business plan. Our limited control over the activities and business practices of these third parties, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.
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Our Interests Are Held In The Form Of Leases That We May Be Unable To Retain. We have working interests in seven oil sands leases in North Central Alberta, Canada. These leases to which we are a party are for a fixed term of 15 years but contain a provision that allows us to extend the term of the lease so long as we meet the minimum level of evaluation as set out by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta. Six of these oil sands leases were successfully continued past their initial 15-year fixed term and are now continued into perpetuity. 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 initial 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. Also, continued oil sands leases must pay escalating rent which is payable at the end of each term year, while annual rent for continued oil sands 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. If we fail to meet the specific requirements of the lease regarding delay or non-payment of yearly rental payments or yearly escalating rents, some or all of our leases may be terminated for failure to pay the required yearly rents. We have one oil sands lease that has not yet been continued past its initial expiry date of April 9, 2024. It is our opinion that we have met the minimum level of evaluation as set out by governmental requirements to continue this lease beyond its 15-year expiry date. There can be no assurance that any of the obligations required to maintain each lease will be met. The termination or expiration of our oil sands leases or the working interests relating to our leases may reduce our opportunity to exploit a given prospect for production and thus could have a material adverse effect on our business, results of operations and financial condition.
We Expect Our Operating Expenses To Increase Substantially In The Future And We May Need To Raise Additional Funds. We have a history of net losses and expect that our operating expenses will increase substantially over the next 12 months as we continue to move forward to develop our oil sands leases. In addition, we may experience a material decrease in liquidity due to unforeseen cash calls or other events and uncertainties. As a result, we may need to raise additional funds, and such funds may not be available on favourable terms, if at all. If we cannot raise funds on acceptable terms, we may not be able to execute our business plan, take advantage of future opportunities or respond to competitive pressures or unanticipated requirements. This could have a material adverse effect on our business, results of operations and financial condition.
Our Ability To Produce Sufficient Quantities Of Oil From Our Properties May Be Adversely Affected By A Number Of Factors Outside Of Our Control. The business of exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil sands wells involves the risk that the wells may be unproductive or that, although productive, the wells may not produce oil in economic quantities. Other hazards such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well could become uneconomic due to, for example, pressure depletion, water encroachment or mechanical difficulties, which could impair or prevent the production from the well. There can be no assurance that oil will be produced from all of our properties in which we have interests. Marketability of any oil that we acquire or discover may be influenced by numerous factors beyond our control. The marketability of our production will depend on the proximity of our reserves to and the capacity of, third party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or insufficient capacity of these facilities and services could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance. There may be periods of time when pipeline capacity is inadequate to meet our oil transportation needs. During periods when pipeline capacity is inadequate, we may be forced to reduce production or incur additional expense as existing production is compressed to fit into existing pipelines. Other risk factors include availability of drilling and related equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. Our ability to manage these factors could have a material adverse effect on our business, results of operations and financial condition.
We Do Not Control All Of Our Operations. We do not operate all of our oil sands properties and we therefore have limited influence over the testing, drilling and production operations of those properties. Currently, we have a 90% working interest on four oil sands leases, a 100% working interest on one oil sands lease, where we are the operator of the 90% and 100% leases. We also have a 25% working interest on two oil sands leases where one of our joint venture partners is the operator. All seven oil sands leases are located in the Peace River oil sands area of Alberta, Canada. Our lack of operational control of the two leases currently not operated by us means we are exposed to the following possibilities:
| ● | the operator might initiate exploration or development on a faster or slower pace than we prefer, or shut-in a currently existing project; |
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| ● | the operator might propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which could mean that we are unable or decline to participate in the project or share in the revenues generated by the project; |
| ● | if the operator does not initiate a joint operation proposal to conduct further operations on these two leases, the non-operators are entitled to propose a joint operation that is separate from any already existing project. As a non-operator on those two leases, we might be unable to pursue further operations on the two leases unless we and possibly other joint participating non-operators directly pay the entire cost thereof. |
Any of these events could materially reduce the value of those properties affected.
Aboriginal Peoples May Make Claims Regarding The Lands On Which Our Operations Are Conducted. The AER governs our operations in Alberta, Canada and they have implemented a directive (“Directive 056”) through which the government of Alberta has issued its First Nations Consultation Policy on Land Management and Resource Development on May 16, 2005. The AER expects that all industry applicants adhere to this policy and the consultation guidelines. These requirements and expectations apply to the licensing of all new energy developments and all modifications to existing energy developments, as covered in Directive 056. In the policy, the government of Alberta has developed consultation guidelines to address specific questions about how consultation for land management and resource development should occur in relation to specific activities. Prior to filing an application, we must address all questions, objections, and concerns regarding our proposed development projects and attempt to resolve them. This includes concerns and objections raised by members of the public, industry, government representatives, First Nations, Métis, and other interested parties. This process can cause significant delays in obtaining a drilling permit for exploration and/or a production well license for both oil and gas and could have a material adverse effect on our operations.
Our Operations Are Subject To A Wide Range of Environmental Legislation and Regulation From All Levels Of Government Of Which We Have No Control. Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures, and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for cleanup costs and damages. The costs of complying with environmental legislation in the future could have a material adverse effect on our business, results of operations and financial condition. We anticipate that changes in environmental legislation may require, among other things, reductions in emissions to the air from its operations and result in increased capital expenditures. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on our business, results of operations and financial condition.
Market Fluctuations In The Prices Of Oil Could Adversely Affect Our Business. Prices for oil tend to fluctuate significantly in response to factors beyond our control. These factors include, but are not limited to, the ongoing wars in the Middle East and actions of the Organization of Petroleum Exporting Countries and its maintenance of production constraints, the U.S. political and economic environment, weather conditions, the availability and market acceptance of alternate fuel sources, transportation interruption, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that could limit future drilling activities for the industry. Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil pricing not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in oil prices could result in non-cash charges to earnings due to write-downs. Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation of projects. We expect that commodity prices will continue to fluctuate significantly in the future.
Our Stock Price Could Decline. Our common stock is traded on the OTC marketplace. There can be no assurance that an active public market will continue for our common stock or that the market price for our common stock will not decline below its current price. Such price may be influenced by many factors, including but not limited to, investor perception of us and our industry and general economic and market conditions. The trading price of our common stock could be subject to wide fluctuations in response to announcements of our business developments or our competitors, quarterly variations in operating results, and other events or factors. In addition, stock markets have experienced extreme price volatility in recent years. This volatility has had a substantial effect on the market prices of companies, at times for reasons unrelated to their operating performance. Such broad market fluctuations may adversely affect the price of our common stock. Our stock price may decline as a result of future sales of our shares or the perception that such sales may occur.
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We Could Be Subject To SEC Penalties If We Do Not File All Of Our SEC Reports. Although we are presently up to date in our current filings, in the past we have not timely filed all of our annual and quarterly reports required to be filed by us with the SEC, in a timely manner. It is possible that the SEC could take enforcement action against us, including potentially the de-registration of our securities, if we fail to file our annual and quarterly reports in a timely manner as required by the SEC. If the SEC were to take any such actions, it could adversely affect the liquidity of trading in our common stock and the amount of information about our Company that is publicly available.
Broker-Dealers Are Not Permitted To Solicit Trades In Our Common Stock. Our common stock is considered to be a “penny stock” because it meets one or more of the definitions of “penny stock” in Rule 3a51-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The principal result or effect of being designated a “penny stock” is that securities broker-dealers cannot recommend the stock and may only trade in it on an unsolicited basis. The continued inability of brokers to recommend our stock could have a material adverse effect on our business, results of operations and financial condition.
Risks Related To Broker-Dealer Requirements Involving Penny Stocks / Risks Affecting Trading and Liquidity. Section 15(g) of the Exchange Act and Rule 15g-2 promulgated thereunder by the SEC require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor’s account. These rules may have the effect of reducing the level of trading activity in the secondary market, if and when one develops. Potential investors in our common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be “penny stock.” Moreover, SEC Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor’s financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in our stock to resell their shares to third parties or to alternatively dispose of them in the market or otherwise.
| ITEM 2. | PROPERTIES |
Oil and Gas Properties
Acreage
Currently, we have a 90% working interest in four oil sands leases, a 100% working interest in one oil sands lease, and a 25% working interest in an additional two oil sands leases in the Peace River oil sands area of Alberta. These seven oil sands leases cover 19,610 gross acres (7,936 gross hectares) with our Company having 13,442 net acres (5,440 net hectares). We are the operator of five of these oil sands leases where we have working interests of either 90% or 100%. For further information, see Oil and Gas Properties on our Balance Sheet and Note 3, 4 and 5 in the notes to our consolidated financial statements contained herein.
The following table summarizes, by geographic area, our gross and net developed and undeveloped acreage as of September 30, 2019:
sawn lake properties - Peace River Oil Sands as of September 30, 2019
Gross Hectares | Net Hectares | Gross
Acres | Net Acres | |||||||||||||
| Developed Acreage | ||||||||||||||||
| Alberta, Canada | 0 | 0 | 0 | 0 | ||||||||||||
| Total | 0 | 0 | 0 | 0 | ||||||||||||
| Undeveloped Acreage | ||||||||||||||||
| Alberta, Canada | 7,936 | 5,440 | 19,610 | 13,442 | ||||||||||||
| Total | 7,936 | 5,440 | 19,610 | 13,442 | ||||||||||||
| TOTAL Developed and Undeveloped | 7,936 | 5,440 | 19,610 | 13,442 | ||||||||||||
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Our 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:
| (i) | 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; |
| (ii) | 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; and |
| (iii) | 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. |
Escalating yearly rents can be offset by eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease.
Summary of Oil and Gas Reserves
We did not have our properties independently assessed and evaluated for reserves and resources as of September 30, 2019. As of September 30, 2015, DeGolyer and MacNaughton Canada Limited (“DeGolyer”) in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles, did assess and evaluate our properties for reserves and resources. Our Company reported no proved reserves as of September 30, 2015.
Drilling and Other Exploratory and Development Activities
The following table summarizes the results of our drilling activities in the Peace River oil sands area of Alberta during the fiscal years ended September 30, 2019, 2018 and 2017.
| Development (Net Wells) | Exploratory (Net Wells) | |||||||||||||||||||||||||||||||
| Oil | Gas | Service
Well | Dry | Oil | Gas | Service Well | Dry | |||||||||||||||||||||||||
| September 30, 2019 | ||||||||||||||||||||||||||||||||
| Alberta, Canada | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||
| September 30, 2018 | ||||||||||||||||||||||||||||||||
| Alberta, Canada | – | – | – | – | * | – | – | – | ||||||||||||||||||||||||
| September 30, 2017 | ||||||||||||||||||||||||||||||||
| Alberta, Canada | – | – | – | – | 0.25 | – | – | – | ||||||||||||||||||||||||
* - On February 15, 2018, we entered into a contribution agreement with a third-party to drill a well on one of our Sawn Lake oil sands leases in which we acquired cores and logs through the Bluesky formation, but did not acquire a working interest in that well.
Productive Wells
As of the fiscal year ended September 30, 2019 all of our producing wells were shut-in in February 2016.
Present Activities – Peace River Oil Sands, Alberta Canada (Sawn Lake Properties)
Currently we have no wells in the process of being drilled. 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 over the last 3 years we have successfully applied to the AER to continue the best sections of our oil sands properties past their initial 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.
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We are focused on developing the bitumen resources located on our Sawn Lake properties using thermal recovery technology development. 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 commenced on September 16, 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. The production results of the current SAGD Project successfully confirmed the capability of the Bluesky reservoir to produce using thermal recovery technology. 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 successful results of our joint SAGD Project were used to update our reservoir models and will be used in the preparation of an updated independent evaluation of our Sawn Lake properties.
Regulatory approval was received in December 2017 for a commercial expansion of the existing SAGD Project facility site where we have a 25% working interest. 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). 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. 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.
In accordance with the Farmout Agreement, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project, in return for a net 25% working interest in 11 sections where we 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 our Company, not to exceed $30,000 per month. 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 and continues to be funded by the agreement. The Farmee shall also 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 on July 30, 2013 between the Company and the operator of the SAGD Project.
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. 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.
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 a 90% working interest. The final performance results and revised reservoir modeling studies from our current SAGD Project will be used to fine-tune our HCSS Project facility design before we initiate start-up operations on the half 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 project.
| ITEM 3. | 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 had been filed on November 1, 2018 but had never been served so our Company was not aware of it.
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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 oil sands leases located within our Sawn Lake properties. The Plaintiff further claims that on September 22, 2006, Nearshore and Gemini Strategies LLC (“Gemini”) entered into a royalty conveyance agreement whereby Nearshore sold 1% of the GORR to Gemini. The Plaintiff further states that Gemini acquired the 1% GORR as agent for Provident, Grey K Fund LP (“Grey K”) and Grey K Offshore Fund Ltd. (“Grey K Offshore”). The Plaintiff further claims that on September 22, 2006, Gemini delivered a notice of assignment, in accordance with the Canadian Association of Petroleum Landmen Assignment Procedure (the “1993 CAPL”), to the grantors of the 1% GORR, novating Provident (66.67%, net 0.6667%) Grey K (19.33%, net 0.1933%) and Grey K Offshore (14%, net 0.14%) into the GORR agreement. The Plaintiff further claims that on September 2, 2009, any legal title in the GORR beneficially owned by Grey K and Grey K Offshore vested in the Crown in right of Alberta pursuant to Section 229(1) of the Business Corporations Act and pursuant to section 15 of the Unclaimed Personal Property and Vested Property Act. The Plaintiff further claims that the GORR was payable by one or more of the Defendants to Provident and that the Defendants are in breach of the GORR agreement by failing to pay the GORR. Despite the allegation within the claim that the GORR was payable to each of Provident, Grey K and Grey K Offshore, the only Plaintiff named in the Amended Statement of Claim is Provident and relief is only being sought by Provident in relation to its purported 0.67% interest.
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.
Our 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. See Item 1 “Business” under the heading “Royalty Agreements” in this annual report on Form 10-K. We plan to vigorously defend ourselves against the Plaintiff’s claims.
| ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
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| ITEM 5. | MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Market Information
Deep Well’s stock is currently quoted on the OTC Marketplace under the trading symbol DWOG. The following table sets forth the high and low sales prices for Deep Well common stock as reported on the OTC Marketplace for the fiscal years indicated below. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions:
| High* | Low* | |||||||
| Fiscal September 30, 2018 | ||||||||
| First Quarter | $ | 0.04 | $ | 0.01 | ||||
| Second Quarter | $ | 0.05 | $ | 0.03 | ||||
| Third Quarter | $ | 0.08 | $ | 0.04 | ||||
| Fourth Quarter | $ | 0.06 | $ | 0.03 | ||||
| Fiscal September 30, 2019 | ||||||||
| First Quarter | $ | 0.05 | 0.02 | |||||
| Second Quarter | $ | 0.06 | 0.01 | |||||
| Third Quarter | $ | 0.04 | 0.01 | |||||
| Fourth Quarter | $ | 0.05 | 0.01 | |||||
*Source: OTC Markets
Holders of Record
As of September 30, 2019, we had approximately 141 holders of record of our shares of common stock. Our Company estimates that investment dealers and other nominees are the record holders for approximately 1,839 beneficial holders.
Dividends
We have not paid cash dividends since inception.
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Securities Authorized for Issuance under Equity Compensation Plans
The following table provides information as of September 30, 2019 with respect to shares of Deep Well’s common stock that may be issued under our existing equity compensation plans.
| Equity Compensation Plan | ||||||||||||
Plan Category | (a) Number of securities to be issued upon exercise of outstanding options, warrants and rights | (b) Weighted-average exercise price of outstanding options, warrants and rights | (c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||||||
| Equity compensation plans approved by security holders | 600,000 | (1) | $ | 0.23 | 22,457,460 | (2) | ||||||
| Equity compensation plans not approved by security holders | – | – | – | |||||||||
| Total | 600,000 | $ | 0.23 | 22,457,460 | (2) | |||||||
(1) On November 17, 2014, the Board appointed Mr. Colin Outtrim to its Board and in connection with this appointment the Board granted Mr. Outtrim an option, expiring five years after the date of grant, to purchase 600,000 shares each of common stock at an exercise price of $0.23 per share of common stock, with the option to purchase 200,000 shares vesting immediately and the option to purchase 200,000 shares on November 17, 2015, and another 200,000 shares on November 17, 2016. These shares expired unexercised on November 17, 2019.
(2) Based on 230,574,603 issued and outstanding shares as at September 30, 2019. The maximum number of common shares that may be reserved for issuance under the Stock Option Plan (as defined below), as amended, may not exceed 10% of our Company’s issued and outstanding common shares.
Stock Option Plan
On November 28, 2005 and as amended on December 4, 2013, our Board adopted the Deep Well Oil & Gas, Inc. stock option plan (the “Stock Option Plan”). The Stock Option Plan was approved by a majority of our shareholders at the February 24, 2010 general meeting of shareholders. The Stock Option Plan, which is administered by our Board, permits options to acquire shares of Deep Well’s common stock to be granted to our directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons providing services to our Company. This Stock Option Plan was adopted to provide an incentive to the retention of our directors, officers and employees as well as consultants that we may wish to retain in the future. The maximum number of shares of common stock, which may be reserved for issuance under the Stock Option Plan may not exceed 10% of our issued and outstanding common stock, subject to adjustment as contemplated by the Stock Option Plan. For further information see the notes to our consolidated financial statements contained herein.
Recent Sales of Unregistered Securities
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
There were no repurchases of equity securities by our Company or affiliated purchasers during the fourth quarter of the fiscal year ended September 30, 2019.
| ITEM 6. | SELECTED FINANCIAL DATA |
We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.
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| ITEM 7. | 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” as disclosed in our Annual Report on Form 10-K filed with the Alberta Securities Commission (“ASC”) on SEDAR on January 13, 2020 and the U.S. Securities and Exchange Commission (“SEC”) 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 (“U.S. GAAP”). References in this Annual Report on Form 10-K to “$” are to United States dollars and references to “Cdn$” are to Canadian dollars. On January 3, 2020, the daily rate of exchange for Cdn$, expressed in US$ was Cdn$1.00 = US$0.7699 as reported by the Bank of Canada.
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 U.S. Securities and Exchange Commission’s website at www.sec.gov. The contents of our website are not part of the Annual Report on Form 10-K for the fiscal year ended September 30, 2019.
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 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:
| September 30, | September 30, | |||||||
| 2019 | 2018 | |||||||
| Revenue | $ | – | $ | – | ||||
| Provincial royalty expenses | – | – | ||||||
| Revenue, net of royalty | – | – | ||||||
| Expenses | ||||||||
| Operating expenses | 97,643 | 148,046 | ||||||
| Operating expense covered by Farmout | (97,643 | ) | (148,046 | ) | ||||
| General and administrative | 165,405 | 289,209 | ||||||
| Depreciation, accretion and depletion | 46,036 | 56,032 | ||||||
| Net loss from operations | (211,441 | ) | (345,241 | ) | ||||
| Other income and expenses | ||||||||
| Rental and other income | 6,612 | 9,054 | ||||||
| Interest income | 7,694 | 6,056 | ||||||
| Net loss | $ | (197,135 | ) | $ | (330,131 | ) | ||
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There was no production volumes or revenues for the fiscal years ending September 30, 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 September 30, 2019, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $20.6 million (Cdn$27.3 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 year ended September 30, 2019, our general and administrative expenses decreased by $123,804 compared to the year ended September 30, 2018, which was primarily due to decreases in engineering, and audit fees. We also received $360,000 during the current fiscal year from the Farmee in accordance with a Farmout Agreement to offset some of our monthly expenses. After adjusting out the non-cash items for foreign exchange loss, and the funds we received from the Farmee, our general and administrative expenses were $523,117 for the year ended September 30, 2019 compared to $643,080 for the year ended September 30, 2018.
For the year ended September 30, 2019, our depreciation and accretion expense decreased by $9,996 compared to the year ended September 30, 2018, which was primarily due to the depreciating value of our assets. Our 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.
For the year ended September 30, 2019, our rental and other income decreased by $2,442 compared to the year ended September 30, 2018.
As a result of the above transactions, our net loss and loss from operations for the year ended September 30, 2019 decreased by $132,996 compared to the year ended September 30, 2018. As discussed above this decrease was primarily due to the decreases in engineering and audit fees.
Liquidity and Capital Resources
As of September 30, 2019, our total assets were $22,677,977 compared to $22,827,332 as of September 30, 2018.
As of September 30, 2019, our total liabilities were $571,384 compared to $538,604 as of September 30, 2018. There was no significant change in our total liabilities from the September 30, 2018 year end.
For the year ended September 30, 2019, we performed an assessment of our carrying costs of our unproven oil sands properties and determined that no write-down of our oil and gas properties as of September 30, 2019 was necessary. No write-downs of our unproven oil sands properties were recorded in the year ended September 30, 2018.
Our working capital is as follows.
| September 30, 2019 | September 30, 2018 | |||||||
| Current Assets | $ | 167,379 | $ | 363,891 | ||||
| Current Liabilities | 70,992 | 45,137 | ||||||
| Working Capital | $ | 96,387 | $ | 318,754 | ||||
As of September 30, 2019, our Company had working capital of $96,387 compared to our working capital of $318,754 as of September 30, 2018. This decrease is mainly due to cash used for general and administrative expenses.
On July 31, 2013, we entered into the Farmout Agreement to fund our share of the costs of our joint SAGD Project. As of September 30, 2019, we recorded $38,213 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.
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As reported on our Consolidated Statement of Cash Flows under “Operating Activities”, for the year ending September 30, 2019, our net cash used in operating activities was $177,258 compared to $343,396 for the year ended September 30, 2018. This decrease of $166,138 was primarily the result of a decrease in operating expenses, which included engineering fees and audit fees.
As reported on our Consolidated Statement of Cash Flows under “Investing Activities”, we had a decrease of $612,839 in the investment in our oil and gas properties for the year ended September 30, 2019, compared to the year ended September 30, 2018. This decrease is primarily due to the cash contribution of $395,500 (Cdn$500,000) we paid in February 2018 to a third-party operator who was drilling into a deeper formation below our properties, to drill and acquire cores and logs for us through the Bluesky formation on one of our oil sands leases.
As reported on our Consolidated Statement of Cash Flows under “Financing Activities”, for the year ended September 30, 2019 and September 30, 2018, we received $15,000 from one of our directors for the exercise of his stock options. We also had a decrease of $245,184 compared to the year ended September 30, 2018. This decrease is due to a $245,184 refund we received in June 2018, which was related to a return of capital distribution our Company issued in September of 2013.
Our cash and cash equivalents for the year ending September 30, 2019 were $49,715 compared to $298,241 in the year ending September 30, 2018. This decrease of $248,526 in cash was primarily due to general and administrative expenses.
As of September 30, 2019, we had no long-term debt other than our estimated asset retirement obligations on our oil and gas properties.
Our current SAGD Project capital and operating costs are covered under the terms of the Farmout Agreement. 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 stockholders will experience dilution in the percentage of their ownership of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so, we may be forced to delay our business plans until adequate funding is obtained.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Cautionary Note Regarding Forward-Looking Statements
This Annual Report, 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 Annual 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; |
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| ● | 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; |
| ● | 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 stockholders’ equity; |
| ● | competition; |
| ● | changes in labor, equipment and capital costs; |
| ● | future acquisitions or strategic partnerships; |
| ● | the risks and costs inherent in litigation; |
| ● | imprecision in estimates of reserves, resources and recoverable quantities of oil, bitumen and natural gas; |
| ● | product supply and demand; |
| ● | changes and amendments in the Canadian Oil and Gas Evaluation Handbook and or the Petroleum Resources Management System to general disclosure of reserves and resources standards and specific annual reserves and resources disclosure requirements for reporting issuers with oil and gas activities; |
| ● | future appraisal of potential bitumen, oil and gas properties may involve unprofitable efforts; |
| ● | the ability to meet minimum level of requirements and obtain approval from Alberta Energy to continue our oil sands leases beyond their expiry dates; |
| ● | the ability to pay 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 |
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| ● | the additional risks and uncertainties, many of which are beyond our control, referred to elsewhere in this Annual 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” as disclosed in this annual report on Form 10-K for the fiscal year ended September 30, 2019 filed with the United States Securities and Exchange Commission (“SEC”) and the Alberta Securities Commission (“ASC”) on SEDAR. 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 7A. | 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 are not required to provide the information required under this item.
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Deep Well Oil & Gas, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Deep Well Oil & Gas, Inc. (the “Company”) as of September 30, 2019 and 2018, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, 2019 and 2018, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Turner, Stone & Company, L.L.P.
Dallas, Texas
January 13, 2020
We have served as the Company’s auditor since 2015.
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DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Consolidated Balance Sheets
September 30, 2019 and September 30, 2018
| September 30, | September 30, | |||||||
| 2019 | 2018 | |||||||
| ASSETS | ||||||||
| Current Assets | ||||||||
| Cash and cash equivalents | $ | 49,715 | $ | 298,241 | ||||
| Accounts receivable | 83,398 | 40,920 | ||||||
| Prepaid expenses | 34,266 | 24,730 | ||||||
| Total Current Assets | 167,379 | 363,891 | ||||||
| Long-term investments | 396,782 | 398,055 | ||||||
| Oil and gas properties, net, based on full cost method of accounting | 22,040,307 | 21,975,868 | ||||||
| Property and equipment, net | 73,509 | 89,518 | ||||||
| TOTAL ASSETS | $ | 22,677,977 | $ | 22,827,332 | ||||
| LIABILITIES | ||||||||
| Current Liabilities | ||||||||
| Accounts payable and accrued liabilities | $ | 69,617 | $ | 45,137 | ||||
| Accounts payable and accrued liabilities – related parties | 1,375 | – | ||||||
| Total Current Liabilities | 70,992 | 45,137 | ||||||
| Asset retirement obligations (Note 10) | 500,392 | 493,467 | ||||||
| TOTAL LIABILITIES | 571,384 | 538,604 | ||||||
| (Commitments and contingencies Note 15) | ||||||||
| SHAREHOLDERS’ EQUITY | ||||||||
| Common Stock: (Note 11) | ||||||||
| Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 230,574,603 shares (September 30, 2018 – 230,574,603 shares) | 230,574 | 230,574 | ||||||
| Additional paid in capital | 43,104,276 | 43,104,276 | ||||||
| Subscriptions receivable – related party | – | (15,000 | ) | |||||
| Accumulated deficit | (21,228,257 | ) | (21,031,122 | ) | ||||
| Total Shareholders’ Equity | 22,106,593 | 22,288,728 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | $ | 22,677,977 | $ | 22,827,332 | ||||
See accompanying notes to the consolidated financial statements
21
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Consolidated Statements of Operations
For the Years Ended September 30, 2019 and 2018
| September 30, | September 30, | |||||||
| 2019 | 2018 | |||||||
| Revenue | $ | – | $ | – | ||||
| Royalty refunds (expenses) | – | – | ||||||
| Revenue, net of royalty | – | – | ||||||
| Expenses | ||||||||
| Operating expenses | 97,643 | 148,046 | ||||||
| Operating expense covered by Farmout | (97,643 | ) | (148,046 | ) | ||||
| General and administrative | 165,405 | 289,209 | ||||||
| Depreciation, accretion and depletion | 46,036 | 56,032 | ||||||
| Net loss from operations | (211,441 | ) | (345,241 | ) | ||||
| Other income and expenses | ||||||||
| Rental and other income | 6,612 | 9,054 | ||||||
| Interest income | 7,694 | 6,056 | ||||||
| Net loss | $ | (197,135 | ) | $ | (330,131 | ) | ||
| Net loss per common share | ||||||||
| Basic and Diluted | $ | (0.0009 | ) | $ | (0.0014 | ) | ||
| Weighted Average Outstanding Shares (in thousands) | ||||||||
| Basic and Diluted | 230,574 | 229,735 | ||||||
See accompanying notes to the consolidated financial statements
22
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Consolidated Statements of Shareholders’ Equity
For the Years Ended September 30, 2019 and 2018
| Common Shares | ||||||||||||||||||||||||
| Additional | ||||||||||||||||||||||||
| Paid in | Subscription | Accumulated | ||||||||||||||||||||||
| Shares | Amount | Capital | Receivable | Deficit | Total | |||||||||||||||||||
| Balance at September 30, 2017 | 229,374,605 | $ | 229,374 | $ | 42,845,292 | $ | – | $ | (20,700,991 | ) | $ | 22,373,675 | ||||||||||||
| Options exercised, June 2018 | 1,199,998 | 1,200 | 13,800 | – | – | 15,000 | ||||||||||||||||||
| Subscription receivable | – | – | – | (15,000 | ) | (15,000 | ) | |||||||||||||||||
| Distribution refund | – | – | 245,184 | – | – | 245,184 | ||||||||||||||||||
| Net Loss for the year ended September 30, 2018 | – | – | – | – | (330,131 | ) | (330,131 | ) | ||||||||||||||||
| 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 year ended September 30, 2019 | – | – | – | – | (197,135 | ) | (197,135 | ) | ||||||||||||||||
| Balance at September 30, 2019 | 230,574,603 | $ | 230,574 | $ | 43,104,276 | $ | – | $ | (21,228,257 | ) | $ | 22,106,593 | ||||||||||||
See accompanying notes to the consolidated financial statements
23
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Consolidated Statements of Cash Flows
For the Years Ended September 30, 2019 and 2018
| September 30, | September 30, | |||||||
| 2019 | 2018 | |||||||
| Operating Activities | ||||||||
| Net loss | $ | (197,135 | ) | $ | (330,131 | ) | ||
| Items not affecting cash: | ||||||||
| Depreciation, accretion and depletion | 46,036 | 56,032 | ||||||
| Net changes in non-cash working capital (Note 13) | (26,159 | ) | (69,297 | ) | ||||
| Net Cash Used in Operating Activities | (177,258 | ) | (343,396 | ) | ||||
| Investing Activities | ||||||||
| Purchase of equipment | (882 | ) | (940 | ) | ||||
| Investment in oil and gas properties | (93,078 | ) | (705,917 | ) | ||||
| Long-term investments | 7,692 | 5,659 | ||||||
| Net Cash Used in Investing Activities | (86,268 | ) | (701,198 | ) | ||||
| Financing Activities | ||||||||
| Subscription receivable collected | 15,000 | – | ||||||
| Distribution refund | – | 245,184 | ||||||
| Net Cash Provided by Financing Activities | 15,000 | 245,184 | ||||||
| Decrease in cash and cash equivalents | (248,526 | ) | (799,410 | ) | ||||
| Cash and cash equivalents, beginning of year | 298,241 | 1,097,651 | ||||||
| Cash and cash equivalents, end of year | $ | 49,715 | $ | 298,241 | ||||
| Supplemental Cash Flow Information: | ||||||||
| Cash paid for interest | $ | – | $ | – | ||||
| Cash paid for income taxes | $ | – | $ | – | ||||
See accompanying notes to the consolidated financial statements
24
DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)
Notes to the Consolidated Financial Statements
September 30, 2019 and 2018
| 1. | NATURE OF BUSINESS AND BASIS OF PRESENTATION |
Nature of Business
Deep Well Oil & Gas, Inc. was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).
Deep Well together with its subsidiaries, Northern Alberta Oil Ltd. and Deep Well Oil & Gas (Alberta) Ltd, (collectively referred to as the “Company”) is an independent junior oil sands exploration and development company with an existing oil sands land base in the Peace River oil sands area in Alberta, Canada.
These consolidated financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the Company”) and the post-split common stock, with $0.001 par value.
Basis of Presentation
These consolidated financial statements are expressed in U.S. dollars and are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).
These statements reflect all adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the opinion of management, are necessary for a fair presentation of the information contained herein.
| 2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Basis of Consolidation
These consolidated financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. (“Northern”) from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All inter-company balances and transactions have been eliminated.
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 September 30, 2019 and September 30, 2018, respectively.
Crude oil and natural gas properties
The Company follows the full cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full cost method of accounting for oil and gas operations requires that all costs associated with the exploration for and development of oil and gas reserves be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.
Under the full cost method, oil and gas properties are subject to the ceiling test performed quarterly. A ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the "cost centre ceiling". The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not being amortized, and (C) the lower of cost or fair value of unproved properties included in the costs being amortized; less (D) related income tax effects. During the 2019 fiscal year, 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.
Property and Equipment
Property and equipment are stated at cost less accumulated depreciation. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. Only half of the depreciation rate is taken in the year of acquisition. The following is a summary of the depreciation rates used in computing depreciation expense:
| % | ||||
| Software | 100 | |||
| Computer equipment | 55 | |||
| Portable work camp | 30 | |||
| Vehicles | 30 | |||
| Road Mats | 30 | |||
| Wellhead | 25 | |||
| Office furniture and equipment | 20 | |||
| Oilfield Equipment | 20 | |||
| Tanks | 10 | |||
Expenditures for major repairs and renewals that extend the useful life of the asset are capitalized. Minor repair expenditures are charged to expense as incurred. Leasehold improvements are amortized over the greater of five years or the remaining life of the lease agreement.
Depreciation, Depletion and Amortization - Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.
Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred. Since there was no production in the last two fiscal years no depletion has been booked in either year.
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 September 30, 2019, and 2018, asset retirement obligations amount to $500,392 and $493,467, 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 Company is the US dollar, but the functional currency of the Company’s Canadian subsidiaries is the Canadian dollar. 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 have not been material and therefore are included in results of operations and not separately reported as a component of comprehensive income.
26
Accounting Method
The Company recognizes income and expenses based on the accrual method of accounting.
Dividend Policy
The Company has not yet adopted a policy regarding payment of dividends.
Financial, Concentration and Credit Risk
The Company’s consideration or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit insurance limit. As of the 2019 fiscal year end, the Company has approximately $3,470 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 year ended September 30, 2019 and September 30, 2018, the Company recorded no oil sales.
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 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 600,000 potentially dilutive securities excluded from the the diluted earnings per share calculation because their effect would be antidilutive.
Financial Instruments
Financial instruments include cash and cash equivalents, accounts receivable, long-term investments, investment in equity securities, accounts payable and accounts payable - related parties. The fair value of these financial instruments approximates their carrying value because of the short-term maturity of these items unless otherwise noted. The fair value of the investment in equity securities cannot be determined as the market value is not readily obtainable. The equity securities are reported using the cost method.
27
Environmental Requirements
The Company is subject to federal, provincial and local environmental laws and regulations. These laws generally provide for control of pollutants released into the environment and protection of the environment. Under these laws and regulations, the Company could be liable for clean-up costs, other environmental damages and fines or penalties related to the Company’s oilsands operations. When the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated environmental remediation liabilities are recorded. At the report date, environmental requirements related to the oil properties acquired are unknown and therefore an estimate of any future cost cannot be made.
Share-Based Compensation
The Company accounts for stock options granted to directors, officers, employees and non-employees using the fair value method of accounting. The fair value of stock options for directors, officers, employees and their corporate entities are calculated at the date of grant and are expensed over the vesting period of the options on a straight-line basis. For non-employees, the fair value of the options is measured on the earlier of the date at which the counterparty performance is complete or the date at which the performance commitment is reached. The Company uses the Black-Scholes model to calculate the fair value of stock options issued, which requires certain assumptions to be made at the time the options are awarded, including the expected life of the option, the expected number of granted options that will vest and the expected future volatility of the stock. The Company reflects estimates of award forfeitures at the time of grant and revises in subsequent periods, if necessary, when forfeiture rates are expected to change.
Recently Adopted Accounting Standards
In 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. It may affect the equipment leases. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.
Accounting Standard Update No. 2014-09, (“ASU 2014-09”) Revenue from Customers (Topic 606), became effective for us in the period ending September 30, 2018. No significant adjustment was required as a result of adopting the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is expected to be immaterial to the Company’s net income on an ongoing basis.
Estimates and Assumptions
Management uses estimates and assumptions in preparing financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions affect the reported amounts of the assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Actual results could vary from the estimates that were used in preparing these consolidated financial statements.
Significant estimates by management include valuations of oil properties, valuation of accounts receivable, useful lives of long-lived assets, asset retirement obligations, valuation of share-based compensation, and the realizability of future income taxes.
| 3. | OIL AND GAS PROPERTIES |
The Company’s oil sands acreage as of September 30, 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 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; |
28
| 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, the 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. On August 19, 2019, 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; 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 September 30, 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 | $ | 23,796 | $ | 31,514 | ||||
| 2021 | $ | 22,782 | $ | 30,170 | ||||
| 2022 | $ | 29,623 | $ | 39,230 | ||||
| 2023 | $ | 31,188 | $ | 41,303 | ||||
| 2024 | $ | 26,898 | $ | 35,621 | ||||
| Subsequent | $ | 144,465 | $ | 191,318 | ||||
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. Proven oil properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for the period ended September 30, 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.
Farmout Agreement
On July 31, 2013, the Company entered into a Farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund the Company’s share of the Alberta Energy Regulator (“AER”) approved joint Steam Assisted Gravity Drainage Demonstration project (“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 Farmee’s share and the Company’s share of the capital costs and operating expenses for the SAGD Project, in return for a net 25% working interest in 12 sections (now 11 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.
29
| 4. | CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES |
The following table illustrates capitalized costs relating to oil producing activities for the year ended September 30, 2019 and September 30, 2018:
| September 30, 2019 | September 30, 2018 | |||||||
| Unproved Oil and Gas Properties | $ | 22,147,367 | $ | 22,071,787 | ||||
| Accumulated Depreciation and Depletion | (107,060 | ) | (95,919 | ) | ||||
| Net Capitalized Cost | $ | 22,040,307 | $ | 21,975,868 | ||||
Depreciation and depletion expenses for the years ended September 30, 2019 and 2018 were $11,141 and $11,141 respectively.
| 5. | EXPLORATION ACTIVITIES |
The following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the years ended September 30, 2019 and September 30, 2018:
| September 30, 2019 | September 30, 2018 | |||||||
| Acquisition of Properties: | ||||||||
| Proved | $ | – | $ | – | ||||
| Unproved | $ | – | $ | 38,185 | ||||
| Exploration costs | $ | 75,580 | $ | 710,012 | ||||
| Development costs | $ | – | $ | – | ||||
| 6. | INVESTMENT IN EQUITY SECURITIES |
On February 25, 2005, the Company acquired an interest in Signet Energy Inc. (“Signet” formerly Surge Global Energy, Inc.) as a result of a Farmout Agreement dated February 25, 2005. Signet amalgamated with Andora Energy Corporation (“Andora”) in 2007.
As of November 19, 2008, the Company converted its Signet shares into 2,241,558 shares of Andora, which presently represents an equity interest in Andora of approximately 2.24% as of March 31, 2019, which is Andora’s first quarter end. These shares are carried at a nominal value using the cost method and their value is included under oil and gas properties on the Company’s balance sheet.
| 7. | PROPERTY AND EQUIPMENT |
| September 30, 2019 | ||||||||||||
| Accumulated | Net Book | |||||||||||
| Cost | Depreciation | Value | ||||||||||
| Computer equipment | $ | 36,569 | $ | 35,177 | $ | 1,392 | ||||||
| Office furniture and equipment | 34,130 | 31,826 | 2,304 | |||||||||
| Software | 5,826 | 5,826 | – | |||||||||
| Leasehold improvements | 4,936 | 4,936 | – | |||||||||
| Portable work camp | 170,580 | 166,578 | 4,002 | |||||||||
| Vehicles | 38,077 | 38,077 | – | |||||||||
| Oilfield equipment | 249,046 | 223,818 | 25,228 | |||||||||
| Road mats | 364,614 | 355,859 | 8,755 | |||||||||
| Wellhead | 3,254 | 3,254 | – | |||||||||
| Tanks | 96,085 | 64,257 | 31,828 | |||||||||
| $ | 1,003,117 | $ | 929,608 | $ | 73,509 | |||||||
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| September 30, 2018 | ||||||||||||
| Accumulated | Net Book | |||||||||||
| Cost | Depreciation | Value | ||||||||||
| Computer equipment | $ | 35,689 | $ | 34,175 | $ | 1,514 | ||||||
| Office furniture and equipment | 34,130 | 31,249 | 2,881 | |||||||||
| Software | 5,826 | 5,826 | – | |||||||||
| Leasehold improvements | 4,936 | 4,936 | – | |||||||||
| Portable work camp | 170,580 | 164,862 | 5,718 | |||||||||
| Vehicles | 38,077 | 38,077 | – | |||||||||
| Oilfield equipment | 249,046 | 217,511 | 31,534 | |||||||||
| Road mats | 364,614 | 352,108 | 12,506 | |||||||||
| Wellhead | 3,254 | 3,254 | – | |||||||||
| Tanks | 96,085 | 60,721 | 35,364 | |||||||||
| $ | 1,002,237 | $ | 912,720 | $ | 89,518 | |||||||
There was $16,889 of depreciation expense for the year ended September 30, 2019 (September 30, 2018 - $26,942).
| 8. | LONG-TERM INVESTMENTS |
Our Long-term investments consist of cash held in trust on behalf of our potential obligations with the AER. These cash investments earn an interest rate of prime minus 0.375% and mature once our obligations to the AER are satisfied. These investments are required by the AER to ensure that there are sufficient future cash reserves to meet the expected future asset retirement obligations for abandonment and reclamation of the Company’s wells and wellsites and are restricted for this purpose.
| 9. | SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES |
Accounts payable – related parties were $1,375 as of September 30, 2019 (September 30, 2018 - $Nil) for expenses to be reimbursed to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.
Subscriptions receivable – related parties was $ Nil as of September 30, 2019 (September 30, 2018 - $15,000) for the amount owed to the Company from one director for the exercise of his stock options.
As of September 30, 2019, officers, directors, their families, and their controlled entities have acquired 53.96% of the Company’s outstanding common capital stock. This percentage does not include unexercised stock options.
The Company incurred expenses $135,666 to one related party, Concorde Consulting, an entity controlled by a director, for professional fees and consulting services provided to the Company during the year ended September 30, 2019 (September 30, 2018 - $140,274). These amounts were fully paid as of September 30, 2019.
| 10. | ASSET RETIREMENT OBLIGATIONS |
The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the AER to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At September 30, 2019, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $610,291 (September 30, 2018 - $624,354). The fair value of the liability at September 30, 2019 is estimated to be $500,392 (September 30, 2018 - $493,467) 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 24 years.
Changes to the asset retirement obligation were as follows:
| September 30, 2019 | September 30, 2018 | |||||||
| Balance, beginning of period | $ | 493,467 | $ | 493,411 | ||||
| Liabilities incurred | – | – | ||||||
| Effect of foreign exchange | (11,081 | ) | (17,893 | ) | ||||
| Disposal | – | – | ||||||
| Accretion expense | 18,006 | 17,949 | ||||||
| Balance, end of period | $ | 500,392 | $ | 493,467 | ||||
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| 11. | COMMON STOCK |
As of September 30, 2019, the Company had outstanding 230,574,603 shares of common stock.
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 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. 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”. On June 20, 2018, $245,184 was returned to the Company.
Warrants
There were no warrants outstanding as of September 30, 2019 (September 30, 2018 – Nil).
| 12. | STOCK OPTIONS |
On November 28, 2005, and as amended on December 4, 2013, the Board of Deep Well adopted the Deep Well Oil & Gas, Inc. Stock Option Plan (the “Plan’). The Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Plan, is administered by the Board, permits options to acquire shares of the Company’s common stock (the “Common Shares”) to be granted to directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons providing services to the Company or its subsidiaries.
The maximum number of shares, which may be reserved for issuance under the Plan, may not exceed 10% of the Company’s issued and outstanding Common Shares, subject to adjustment as contemplated by the Plan. The aggregate number of Common Shares with respect to which options may be vested to any one person (together with their associates) under the plan, together with all other incentive plans of the Company in any one year shall not exceed 2% of the total number of Common Shares outstanding, and in total may not exceed 6% of the total number of Common Shares outstanding.
Between June 8 to 10, 2018, five directors, two contractors and one employee of the Company, exercised a total of 3,150,000 option shares at an exercise price of $0.05 by way of a cashless exercise to acquire a total of 899,998 common shares of the Company, based upon the market value of the Company’s common stock of $0.07 per share on June 8, 2018, whereby 2,250,002 common shares were withheld by the Company to pay for the exercise price of the options. The stock certificates from the latest exercise of stock options are currently held in escrow upon final approval and release by Management of the Company.
On June 19, 2018, one director of the Company acquired 300,000 common shares of the Company upon exercising stock options, at an exercise price of $0.05 per common share for total gross proceeds to the Company of $15,000.
On October 28, 2018, 250,000 stock options previously granted on October 28, 2013 to a contractor for services in connection with the Farmout Agreement, expired unexercised.
On December 4, 2018, 450,000 stock options previously granted on December 4, 2013 to one director, expired unexercised.
On September 19, 2019, 6,780,000 stock options previously granted on September 19, 2014 to seven directors, two contractors and one employee expired unexercised.
For the year ended September 30, 2019, the Company recorded no share-based compensation expense related to stock options (September 30, 2018 – $Nil). As of September 30, 2019, there was no unrecognized compensation cost related to option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.
| Shares Underlying Options Outstanding | Shares Underlying Options Exercisable | |||||||||||||||||||
| Range of Exercise Prices | Shares Underlying Options Outstanding | Weighted Average Remaining Contractual Life | Weighted Average Exercise Price | Shares Underlying Options Exercisable | Weighted Average Exercise Price | |||||||||||||||
| $0.23 at September 30, 2019 | 600,000 | 0.13 | $ | 0.23 | 600,000 | $ | 0.23 | |||||||||||||
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The aggregate intrinsic value of exercisable options as of September 30, 2019, was $Nil (September 30, 2018 - $Nil).
The following is a summary of stock option activity as at September 30, 2019:
| Number of Underlying Shares | Weighted Average Exercise Price | Weighted Average Fair Market Value | ||||||||||
| Balance, September 30, 2018 | 8,080,000 | $ | 0.36 | $ | 0.29 | |||||||
| Expired, October 28, 2018 | (250,000 | ) | 0.30 | 0.30 | ||||||||
| Expired, December 4, 2018 | (450,000 | ) | 0.34 | 0.36 | ||||||||
| Expired, September 19, 2019 | (6,780,000 | ) | 0.38 | 0.30 | ||||||||
| Balance, September 30, 2019 | 600,000 | $ | 0.23 | $ | 0.18 | |||||||
| Exercisable, September 30, 2019 | 600,000 | $ | 0.23 | $ | 0.18 | |||||||
A summary of stock options at September 30, 2019 and 2018 and changes during the periods then ended is presented below:
| September 30, 2019 | September 30, 2018 | |||||||||||||||
| Shares | Weighted Average Exercise Price | Shares | Weighted Average Exercise Price | |||||||||||||
| Outstanding balance at beginning of period | 8,080,000 | $ | 0.36 | 11,530,000 | $ | 0.29 | ||||||||||
| Exercised, June 8, 2018 | (3,450,000 | ) | 0.05 | |||||||||||||
| Expired, October 28, 2018 | (250,000 | ) | 0.30 | |||||||||||||
| Expired, December 4, 2018 | (450,000 | ) | 0.34 | |||||||||||||
| Expired, September 19, 2019 | (6,780,000 | ) | 0.38 | |||||||||||||
| Outstanding at end of period | 600,000 | $ | 0.23 | 8,080,000 | $ | 0.36 | ||||||||||
| Exercisable | 600,000 | $ | 0.23 | 8,080,000 | $ | 0.36 | ||||||||||
There were no remaining unvested stock options outstanding as of September 30, 2019 (September 30, 2018 – Nil).
Measurement Uncertainty for Stock Options
The Company used the Black-Scholes pricing model (“Black-Scholes”) to value the stock options. This pricing model was developed for use in estimating the fair value of traded “European” options. The stock options that are granted to employees, directors and consultants are non-transferable and some vest over time, and are “American” options. This pricing model requires the input of subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes in the assumptions, and therefore can materially affect the calculated fair value of the stock options. The following assumptions were used in the Black-Scholes pricing model to value the stock options:
Expected Term – Expected term of 5 years represents the period that the Company’s stock-based awards are expected to be outstanding.
Expected Volatility – Expected volatilities are based on historical volatility of the Company’s stock, adjusted where determined by management for unusual and non-representative stock price activity not expected to recur. The expected volatility used ranged from 102% to 122%.
Expected Dividend – The Black-Scholes valuation model calls for a single expected dividend yield as an input. The Company currently pays no dividends and does not expect to pay dividends in the foreseeable future.
Risk-Free Interest rate – The Company bases the risk-free interest rate on the implied yield currently available on U.S. Treasury zero-coupon issues with an equivalent remaining term. The risk-free rate used ranged from 1.31% to 2.07%.
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| 13. | CHANGES IN NON-CASH WORKING CAPITAL |
| September 30, | September 30, | |||||||
| 2019 | 2018 | |||||||
| Accounts receivable | $ | (42,478 | ) | $ | 40,372 | |||
| Prepaid expenses | (9,536 | ) | 11,346 | |||||
| Accounts payable | 25,855 | (121,015 | ) | |||||
| $ | (26,159 | ) | $ | (69,297 | ) | |||
| 14. | INCOME TAXES |
As of September 30, 2019, the Company has approximately $2,190,855 (2018 – $6,442,069) of operating losses expiring through 2039 that may be used to offset future taxable income but are subject to various limitations imposed by rules and regulations of the Internal Revenue Service. The net operating losses are limited each year to offset future taxable income, if any, due to the change of ownership in the Company's outstanding shares of common stock. In addition, at September 30, 2019, the Company had an unused Canadian net operating loss carry-forward of approximately $7,865,973 (2018 – $8,096,433), expiring through 2039. These operating loss carry-forwards may result in future income tax benefits of approximately $2,269,253. However, because realization is uncertain at this time, a valuation reserve in the same amount has been established. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
The components of the net deferred tax asset, the statutory tax rate, the effective rate and the elected amount of the valuation allowance are as follows:
| Year Ended September 30, 2019 | Year Ended September 30, 2018 | |||||||
| Statutory and effective tax rate | ||||||||
| Domestic | ||||||||
| Statutory U.S. federal rate | 21 | % | 21 | % | ||||
| Foreign | 26.75 | % | 27 | % | ||||
| Year Ended September 30, 2019 | Year Ended September 30, 2018 | |||||||
| Income taxes recovered at the statutory and effective tax rate | ||||||||
| Domestic | ||||||||
| Statutory U.S. federal rate | $ | 24,637 | $ | 28,484 | ||||
| Foreign | 21,347 | 52,513 | ||||||
| Timing differences: | ||||||||
| Non-deductible expenses | (12,534 | ) | (21,102 | ) | ||||
| Other deductible charges | ||||||||
| Benefit of tax losses not recognized in the year | (33,450 | ) | (59,895 | ) | ||||
| Income tax recovery (expense) recognized in the year | $ | – | $ | – | ||||
The approximate tax effects of each type of temporary difference that gives rise to deferred tax assets are as follows:
| Year Ended September 30, 2019 | Year Ended September 30, 2018 | |||||||
| Deferred income tax assets (liabilities) | ||||||||
| Net operating loss carry-forwards | $ | 2,563,850 | $ | 3,538,871 | ||||
| Oil and gas properties | (2,043,926 | ) | (1,936,342 | ) | ||||
| Equipment | 204,147 | 209,647 | ||||||
| Valuation allowance | (724,071 | ) | (1,812,176 | ) | ||||
| Net deferred income tax assets | $ | – | $ | – | ||||
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In accordance with generally accepted accounting principles, the Company has its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax returns for the previous five years remain subject to examination. The Company’s income tax returns in state income tax jurisdictions also remain subject to examination for the previous five years. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions, and no adjustments to such reserves were required by generally accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated, therefore no interest or penalty has been included in the provision for income taxes in the consolidated statements of operations.
| 15. | COMMITMENTS |
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.
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 $11,306 per month (Cdn $15,000 per month). As of September 30, 2019, the Company did not owe Concorde Consulting any of this amount.
| 16. | CRUDE OIL AND NATURAL GAS PROPERTY INFORMATION (Unaudited) |
Results of Operations from Oil and Gas Producing Activities
The following table sets forth the results of the Company’s operations from oil producing activities from the Company’s Sawn Lake oil sands properties located in Alberta, Canada, for the years ending September 30, 2019 and 2018:
| September 30, 2019 | September 30, 2018 | |||||||
| Oil sales after royalties | $ | – | $ | – | ||||
| Production (Operating) expenses | – | – | ||||||
| Depreciation, accretion and depletion | (44,457 | ) | (54,036 | ) | ||||
| Oil sales less expenses | (44,457 | ) | (54,036 | ) | ||||
| Income tax expenses | – | – | ||||||
| Results of operations from producing activities | $ | (44,457 | ) | $ | (54,036 | ) | ||
There was no production volumes or revenues for the fiscal years ending September 30, 2019 and 2018, due to a majority of the 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 the Company entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for the Company’s working interest portion of the costs of the SAGD Project before the execution of the Farmout Agreement in return for a net 25% working interest in two oil sands leases where the Company had a working interest of 50%. The Farmee is also required to provide funding to cover monthly administrative expenses of the Company provided that such funding shall not exceed $30,000 per month. The Farmee shall continue to cover the Company’s administrative costs up to $30,000 per month, under the Farmout Agreement, until completion in all substantial respects of the SAGD Project agreement entered into between the Company and the operator of the SAGD Project.
Operating expenses are zero since at this time they are paid for under the Farmout Agreement. Transportation costs are included in these operating costs. The total share of the capital costs and operating expenses of the Company’s joint Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”), has been funded in accordance with the Farmout Agreement, at a net cost to the Company of $Nil. As required by the Farmout Agreement, the Farmee has since reimbursed the Company and or paid the operator in total approximately $20.6 million (Cdn $27.3 million) for the Farmee’s share and the Company’s share of the capital costs and operating expenses of the SAGD Project up to September 30, 2019. These costs include the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator (“OTSG”), production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells, construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the one SAGD well pair when the facility was producing; and the expenses associated with the monthly shut-in operations of the SAGD Project facility. The capital costs of the existing the SAGD Project steam plant facility, with pipelines and one SAGD well pair was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest basis, of which the Company’s share was covered under the Farmout Agreement. These capital costs do not include the start-up operating expenses to initiate oil production from the SAGD well pair.
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SAGD Project Outlook - The SAGD Project has successfully shown the capability of producing oil from the Bluesky reservoir using steam. 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 steam-oil ratio (“SOR”) of the reservoir; and |
| ● | provided critical information required for well and facility design associated with future commercial development. |
The first SAGD well pair, for the SAGD Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection commenced in May 2014 and production started in September of 2014. Production from this one SAGD well pair increased significantly over the 18-month period it produced. Over January and February of 2016 production from the SAGD Project averaged 615 bopd, on a 100% basis (154 bopd net to the Company), with an average SOR of 2.1 from one SAGD well pair. The SOR is reflective of the amount of steam needed to produce one barrel of oil. This SAGD Project was temporarily suspended at the end of February 2016. In early May of 2016, an amended application was submitted to the Alberta Energy Regulator (“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 existing SAGD Project facility site to 3,200 bopd (100% basis). The Company anticipates that only five SAGD well pairs will need to be operating to achieve this production level. The Company anticipates that the commercial expansion to 3,200 bopd (100% basis) would include the reactivation of the existing demonstration project SAGD facility and existing SAGD well pair, the drilling of an additional four wellpairs and expansion of the existing SAGD facility to generate the additional necessary steam. The SAGD Project continues to move forward with completing detailed engineering and assessing potential marketing arrangements for the commercial development expansion to 3,200 bopd (100% basis).
Capitalized Costs Relating Specifically to the SAGD Project
The Company entered into a Farmout Agreement dated July 31, 2013, whereby the Company’s costs of the SAGD Project are paid in full by the Farmee in accordance with the Farmout Agreement; therefore, the Company has not capitalized any of the capital costs and operating expenses paid by the Farmee to the operator of the SAGD Project. See Note 4 herein “Capitalization of Costs Incurred in Oil and Gas Activities”.
Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
See Note 5 herein “Exploration Activities”.
| 17. | Subsequent Event Note |
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 further claims that on September 22, 2006, Nearshore and Gemini Strategies LLC (“Gemini”) entered into a royalty conveyance agreement whereby Nearshore sold 1% of the GORR to Gemini. The Plaintiff further states that Gemini acquired the 1% GORR as agent for Provident, Grey K Fund LP (“Grey K”) and Grey K Offshore Fund Ltd. (“Grey K Offshore”). The Plaintiff further claims that on September 22, 2006, Gemini delivered a notice of assignment, in accordance with the 1993 Canadian Association of Petroleum Landmen Assignment Procedure (the “1993 CAPL”), to the grantors of the 1% GORR, novating Provident (66.67%, net 0.6667%), Grey K (19.33%, net 0.1933%) and Grey K Offshore (14%, net 0.14%) into the GORR agreement. The Plaintiff further claims that on September 2, 2009, any legal title in the GORR beneficially owned by Grey K and Grey K Offshore vested in the Crown in right of Alberta pursuant to Section 229(1) of the Business Corporations Act and pursuant to section 15 of the Unclaimed Personal Property and Vested Property Act. The Plaintiff further claims that the GORR was payable by one or more of the Defendants to Provident and that the Defendants are in breach of the GORR agreement by failing to pay the GORR. Despite the allegation within the claim that the GORR was payable to each of Provident, Grey K and Grey K Offshore, the only Plaintiff named in the Amended Statement of Claim is Provident and relief is only being sought by Provident in relation to its purported 0.67% interest.
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.
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| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
During the fiscal years ended September 30, 2019 and 2018, there were no changes in, or disagreements with, our independent accountant on accounting and financial disclosure matters.
| ITEM 9A. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
As of the end of the fiscal year ended September 30, 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 Exchange Act) 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 fiscal year, 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 SEC 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.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) to provide reasonable assurance regarding the reliability of our financial reporting and consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
Our management, which included our principal executive officer and principal financial officer, assessed our internal control over financial reporting as of September 30, 2019. This assessment was based on criteria for effective internal control over financial reporting described in the internal control integrated framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that, as of September 30, 2019, our internal control over financial reporting was effective.
Attestation Report of the Independent Registered Public Accounting Firm
We are a smaller reporting and emerging growth company within the meaning of Rule 12b-2 under the Exchange Act. Therefore, this Annual Report is not required to include an attestation report of our independent registered public accounting firm, with respect to our internal control over financial reporting. Turner Stone’s audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of our internal control over financial reporting. Accordingly, Turner Stone expressed no such opinion on our internal control over financial reporting as of September 30, 2019.
Changes in Internal Control Over Financial Reporting
There was no change in our internal controls over financial reporting during the year end covered by this Annual Report on Form 10-K that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
| ITEM 9B. | OTHER INFORMATION |
Our Company reported all information that was required to be disclosed on Form 8-K during the fourth quarter of the fiscal year ended September 30, 2019, as covered by this Annual Report.
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| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Directors and Executive Officers
As of September 30, 2019, the directors and executive officers of Deep Well are as follows:
| Name | Age | Director Since |
Position/Office | |||
| Dr. Horst A. Schmid | 86 | 2004 | Director and Chairman of the Board, President and Chief Executive Officer | |||
| Mr. Said Arrata | 79 | 2011 | Director | |||
| Mr. Satya Brata Das | 63 | 2011 | Director | |||
| Mr. Pascal Nodé-Langlois | 72 | 2013 | Director | |||
| Mr. Colin P. Outtrim | 69 | 2014 | Director | |||
| Mr. David Roff | 48 | 2006 | Director | |||
| Mr. Curtis Sparrow | 62 | 2004 | Director and Chief Financial Officer, Corporate Secretary and Treasurer | |||
| Mr. Malik Youyou | 66 | 2008 | Director |
Biographies of Directors and Executive Officers
Brief biographies of the directors and executive officers of Deep Well are set forth below. All directors hold office until the next shareholders’ meeting or until their death, resignation, retirement, removal, disqualification or until their successors have been elected and qualified. Vacancies in the existing Board may be filled by majority vote of the remaining directors. Officers of our Company serve at the will of the Board. As of September 30, 2019, there were no written employment contracts outstanding for officers, other than the consulting contracts as disclosed in this Annual Report on Form 10-K.
Dr. Horst A. Schmid has served as director and Chairman of the Board of Deep Well since February 6, 2004. Since June 29, 2005, he has been the Chief Executive Officer and President of Deep Well. From September 1996 to present, Dr. Schmid has been the director, President and Chief Executive Officer of Portwest Investment Ltd., a private firm, located in Edmonton, Alberta, Canada. Prior to that, Dr. Schmid spent 15 years as Cabinet Minister for the Government of Alberta and 10 years as Commissioner General for Trade and Tourism for the province of Alberta. During that time, he was involved in numerous successful overseas negotiations for the Alberta oil and gas industry, achieving major contracts for Alberta exploration and production service companies. He is the recipient of many Canadian and international awards for his accomplishments. Dr. Schmid received an Honorary Law Degree from the University of Alberta.
Mr. Said Arrata has served as director of Deep Well since March 8, 2011. Mr. Arrata is a highly experienced energy executive who brings a sophisticated understanding of energy company development to the Deep Well Board. Mr. Arrata is the chairman of the board of directors and chief executive officer of Sea Dragon Energy Inc., a firm domiciled in Calgary, Alberta, devoted exclusively to overseas production, and concentrated in Egypt. In 2007 the company he co-founded, Centurion Energy, was sold for $1.2 billion to Dana Gas Inc. and Mr. Arrata subsequently established Sea Dragon Energy Inc. Since May of 2007, Mr. Arrata has been a board member of Dan Gas Inc., a company which operates oil and gas concessions in Egypt and the Province of Kurdistan. Reputed as a company-builder, he focused on building maximum value for shareholders during his more than 40 years in the oil and gas industry during which he held management and board positions with major oil and gas companies in Canada and overseas. Mr. Arrata holds a B.Sc. degree in Petroleum Engineering along with several post-graduate accreditations at various universities in North America and is an active member of several professional engineering and industry associations.
Mr. Satya Brata Das has served as director of Deep Well since March 8, 2011. Mr. Satya Brata Das is a seasoned strategist, author, board director and policy guru. Mr. Das’ guidance and counsel is highly valued in the public, private and philanthropic sectors. Mr. Das advised on more than 50 major files for the governments of Canada, Alberta, and municipalities. Mr. Das’ private sector engagement ranges from start-ups to listed firms. Building on a distinguished career in journalism in the last quarter of the 20th century, Mr. Das launched his advisory firm Cambridge Strategies Inc. at the turn of the millennium. Mr. Das’ proven skills in integrating the political, economic, societal and cultural dimensions of policy challenges have brought effective results to professional and voluntary endeavours. Mr. Das pioneered values-based public policy, using quantitative measures of citizen values to win social license and widespread societal support. Mr. Das is a frequent commentator and public speaker in both national languages, in media and on stage. A best-selling author, Mr. Das’ books include “Dispatches from a Borderless World”; “The Best Country: Why Canada Will Lead the Future”, “Green Oil: Clean Energy for the 21st Century?”, and “Us”. Mr. Das’ volunteer work is deeply informed with a lifelong commitment to human rights as a way of life, and the principles of human dignity espoused by M.K. Gandhi.
Mr. Pascal Nodé-Langlois has served as a director of Deep Well since December 4, 2013. Mr. Nodé-Langlois is a French entrepreneur with a broad experience in banking. In 1975, he founded in Switzerland, the company Stock and Commodity Services SA (“SCS”). In 1991, SCS became Banque SCS Alliance SA (BSA), a fully licensed Swiss bank with branches in Switzerland and subsidiaries abroad. In 2006, after a consistent career of more than 30 years as the principal owner, Managing Director and Chairman of the Board of BSA (previously SCS), Mr. Nodé-Langlois sold his stake in the bank. In 2007, he founded a new financial boutique, in Luxembourg: Voltaire Group SA. This company operates as a holding company. It acquires majority participations and/or creates operating companies with the aim to cover a large portion of the different financial services corresponding to the field of expertise that Mr. Nodé-Langlois developed during his previous activity in banking. Its main present participation is PARfinance SA, a Swiss registered wealth management company.
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Mr. Colin P. Outtrim has served as director of Deep Well since November 17, 2014. Mr. Outtrim is a highly experienced petroleum engineer bringing with him extensive reservoir appraisal knowledge to the Company. Mr. Outtrim has over 40 years of experience in the global petroleum reserves and resources industry and has conducted and or participated in several hundred reservoir engineering and economic evaluation projects covering oil, gas and geothermal properties in all parts of the world having asset values from between one million to 20 billion dollars. Early in his career he worked with the Alberta Government Energy Resources and Conversation Board (now known as the Alberta Energy Regulator or “AER”) as a Reserves Engineer assessing the Alberta oil sands, at which time he also published and co-authored a paper entitled “The Oil Sands Reserves of Alberta”. From 1992 to 2004, he was the co-founder, President and CEO of Outtrim Szabo Associates Ltd. which served petroleum companies undertaking energy developments around the world. In 2004, Outtrim Szabo Associates Ltd. was acquired by DeGolyer and Mr. Outtrim became president and a director of DeGolyer until his retirement in 2012. From 2008 to 2012, the Company engaged DeGolyer to prepare the Company’s independent reserves and resources analysis reports, at which time Mr. Outtrim was providing independent consulting engineering services to the Company through DeGolyer. His career has provided him broad experience reporting to audit committees as a “qualified reserves evaluator and auditor”. He is one of a few expert members from around the world selected to sit on and serve as a technical member of the Experts Group sub-committee on the United Nations Economic Commission for Europe, the United Nations Framework Classification for the standardization of petroleum reserves and resource definitions, and has recently completed a three-year term on the board of trustees of the Society of Petroleum Engineers Canadian Educational Trust Fund as trustee and treasurer. He is currently serving as director and reserves audit committee chairman of CaiTerra International Energy Corporation and currently provides reservoir engineering advisory services to Tallahassee Resources Inc. He is also the past chairman of the Petroleum Society of the Canadian Institute of Mining. Mr. Outtrim holds a Bachelor of Applied Science in Geological Engineering from the University of British Columbia and is a registered Petroleum Engineer. Mr. Outtrim completed his professional qualifications at the highest level with the Institute of Corporate Directors (“ICD”) and attained his ICD.D designation.
Mr. David Roff has served as a director of Deep Well since April 3, 2006. Mr. Roff is the Vice President, Business Development at Cranson Capital, an Exempt Market Dealer a position he has held since Sept 2017. He is also a real estate advisor to Globalive Capital a position he has held since April 2015. Globalive Capital is a family office. Mr Roff is also co-president of Brave Investment Corporation, a private consulting and investment company and has held this position since 2001. He has over twenty years experience investing in, building and operating companies. Mr. Roff is a Chartered Professional Accountant and obtained his designation while working at Coopers & Lybrand Consulting. He also has a B.A. degree from the University of Western Ontario. Mr. Roff a director of Findev (FDI).
Mr. Curtis James Sparrow has served as director of Deep Well since February 6, 2004. Mr. Sparrow has also been the Chief Financial Officer, Corporate Secretary and Treasurer of Deep Well. Since the mid-1980s, Mr. Sparrow has been a self-employed management consultant specializing in the natural resource sector. Mr. Sparrow has been involved in the oil and gas industry in various capacities for over 38 years. He has held directorships and senior officer positions with junior exploration and development companies before becoming a self-employed consultant. He has also participated in the marketing side of the oil and gas industry, and was part of an acquisition team formed to assess and develop a bid for a multi-billion dollar integrated oil company. His experience also includes corporate and project management, international businesses and mining. Mr. Sparrow is a National Association of Corporate Directors (“NACD”) Governance Fellow. He has demonstrated his commitment to boardroom excellence by completing NACD’s comprehensive program of study for corporate directors. He supplements his skill sets through ongoing engagement with the director community, and access to leading practices. The NACD is the recognized authority focused on advancing exemplary board leadership and establishing leading boardroom practices. Mr. Sparrow received his Bachelor of Science Degree in Engineering and Master’s Degree in Business Administration from the University of Alberta. Mr. Sparrow is also a registered Professional Engineer a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA), the Society of Petroleum Engineers (SPE), and the American Finance Association (AFA).
Mr. Malik Youyou has served as director of Deep Well since August 20, 2008. Mr. Youyou is an experienced international entrepreneur, investor and director of several companies. With more than three decades of business experience in highly competitive global markets, beginning in his native France, Mr. Youyou brings a strong international perspective to Deep Well's Board. Mr. Youyou has created and led several companies involved in the development, branding, and marketing of luxury goods from leading international houses.
Family Relationships
There are no family relationships among the directors and executive officers of our Company.
Involvement in Certain Legal Proceedings
The following does not describe any past legal proceeding to which Deep Well or its subsidiaries are a party. In the past ten years:
No bankruptcy petition has been filed by or against any business of which any current director was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time.
No current director has been convicted in a criminal proceeding and is not subject to a pending criminal proceeding (excluding traffic violations and other minor offenses).
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No current director has been the subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities.
No current director has been the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (f)(3)(i) of section 229.401 of Regulation S-K, or to be associated with persons engaged in any such activity.
No current director has been found by a court of competent jurisdiction in a civil action or by the SEC to have violated a Federal or State securities law that has not been reversed, suspended, or vacated.
No current director has been found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law that has not been subsequently reversed, suspended or vacated.
No current director has been the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any federal or state securities or commodities law or regulation; any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order or disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity.
No current director has been the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization, any registered entity, or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
Section 16 (a) Beneficial Ownership Reporting Compliance
Based solely on the review of Forms 3 and 4 received by us during the September 30, 2019 fiscal year, as required under Section 16(a)(2) of the Exchange Act, all of our directors and officers reported all their transactions as required on a Form 4, on a timely basis.
Code of Ethics
Our Company has adopted a formal Code of Business Conduct and Ethics policy governing our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, including our directors and employees, to promote honest and ethical conduct, full, fair, accurate, understandable and timely disclosure in our reports to the SEC, and compliance with applicable governmental laws, rules and regulations. A copy of our Code of Business Conduct and Ethics policy may be obtained, free of charge, from our website at www.deepwelloil.com, or by written request addressed to the Corporate Secretary of Deep Well Oil & Gas, Inc., Suite 700, 10150 – 100 Street NW, Edmonton, Alberta, T5J 0P6, Canada. Incorporated by reference, as Exhibit 14.1, is a copy of our Code of Business Conduct and Ethics policy filed with the SEC on January 13, 2015.
Corporate Governance
Director Independence
Our Board with the assistance of management, reviews and determines director independence requirements for each director, based on the NASDAQ standards for director independence as set forth by the NASDAQ Stock Market Rule 5605(a)(2) and pursuant to Rule 10A-3 of the Exchange Act of 1934. Our Board determined that as of September 30, 2019 and 2018, the Company’s Board consisted of five independent and three non-independent directors. It was determined that Dr. Horst A. Schmid and Mr. Curtis Sparrow, who serve as directors of our Company, are not independent because they serve our Company as President and CEO and Chief Financial Officer, respectively. It was also determined that Mr. Malik Youyou, who serves as a director of our Company, is not independent because he owns a controlling interest of our Company’s issued and outstanding common stock. The directors of our Company, when they became directors and our Company’s opinion as to each director’s independence are as follows:
| Name | Year Appointed | Director Independence | ||
| Dr. Horst A. Schmid | 2004 | Non-independent director – Chairman of the Board | ||
| Mr. Said Arrata | 2011 | Independent director | ||
| Mr. Satya Brata Das | 2011 | Independent director | ||
| Mr. Pascal Nodé-Langlois | 2013 | Independent director | ||
| Mr. Colin P. Outtrim | 2014 | Independent director | ||
| Mr. David Roff | 2006 | Independent director | ||
| Mr. Curtis Sparrow | 2004 | Non-independent director | ||
| Mr. Malik Youyou | 2008 | Non-independent director |
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Corporate Governance and Nominating Committee
Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of the Corporate Governance and Nominating committee. This committee currently does not have a specific policy in place with respect to evaluating candidates for director nominees at this time.
Any shareholder proposals to be presented at our next annual meeting of shareholders (including the inclusion of shareholder director nominees) must be given in writing to our Company, along with proof of ownership of our stock in accordance with Rule 14a-8(b)(2), and received at our Company’s principal executive office, located at Suite 700, 10150 – 100 Street NW, Edmonton, Alberta, T5J 0P6. Any such proposal must comply with the rules pursuant to Rule 14a-8 under the Exchange Act and in accordance with our Company’s Bylaws. Our Company reserves the right to reject, rule out of order or take other appropriate action with respect to any proposal that does not comply with these and other applicable requirements, including conditions set forth in our bylaws and conditions established by the SEC. If our Company has its shareholder meeting by way of resolution any complying proposal will be considered at that time. It is recommended that shareholders submitting proposals direct them to our Corporate Secretary and utilize certified mail return receipt requested in order to provide proof of timely receipt. Copies of the bylaws are available by writing to our Company at the mailing address above or downloading them as previously filed on September 3, 2009 with the SEC on Form 8-K.
Audit Committee
Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of the Audit committee. Of our eight directors serving on our Board, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou have been determined by our Board not to be independent directors under director independence standards noted above. Our Board has determined that Mr. David Roff, as a director of our Company, is independent and is also recognized as an audit committee financial expert. Mr. Roff is a Chartered Professional Accountant, with a B.A. degree from the University of Western Ontario, and he worked as an auditor from 1995 to 1998.
Compensation Committee
Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of our Compensation committee. Of our eight directors serving on our Board, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou have been determined by our Board not to be independent directors under director independence standards noted above. During the September 30, 2019 fiscal year Dr. Horst A. Schmid and Mr. Curtis Sparrow served as officers of our Company.
On or about July 31, 2018, a majority of shareholders approved by written consent, on a non-binding basis, the compensation paid to our Company's named executive officers.
Reserves and Resources Committee
On January 3, 2015, our Board appointed a Reserves and Resources Committee consisting of four Board members, three of which are independent. Our Board appointed the following Directors: Mr. Said Arrata, Mr. Colin Outtrim, Mr. David Roff and Mr. Curtis Sparrow to serve on this committee and Mr. Colin Outtrim was appointed as chairman of the committee. Of our four members serving on this committee it was determined by our Board that Mr. Curtis Sparrow is not an independent member or director under director independence standards noted above.
The purpose of this committee is to assist our Board in monitoring: (i) the integrity of the independent reserves and resources estimates and related U.S. and Canadian regulatory disclosures of our Company; and (ii) the qualifications and independence of the independent reservoir engineers, geologists and geophysicists.
Our Company’s reserves, if any, and/or resources data and estimates are prepared by independent examination and evaluation of our Company’s production data, reservoir pressure data, logs, geological data, and offset analogies in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by the independent reserves evaluators are required to meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Our Company’s independent reserves evaluators are provided full access to complete and accurate information pertaining to our Company’s properties, and to all applicable personnel of our Company. Our Company’s reserves, if any, and/or resources estimates and process for developing such estimates are reviewed by our Company’s current Reserves and Resources Committee and approved by management. Management on behalf of our Board ensures compliance with SEC disclosure and internal control requirements along with verifying the independence of all third-party consultants. Our Company’s management is ultimately responsible for reserves, if any, and or resources estimates and reserves disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.
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| ITEM 11. | EXECUTIVE COMPENSATION |
On July 31, 2018, a majority of our shareholders approved on an advisory basis the compensation paid to the Company’s named executive officers (also known as “Say-on-Pay”). At the Company’s 2013 general meeting of shareholders held on September 17, 2014, a majority of our shareholders approved the frequency of which to hold the say-on-pay advisory vote on the compensation paid to the Company’s named executive officers be every three years. This non-binding “Frequency Vote” must be considered by our Company’s shareholders at least once every six years. We will have another non-binding vote on the frequency in which to hold an advisory vote on compensation paid to our Company’s named executive officers within six years from the last vote held on September 17, 2014.
Summary Compensation Table
The following table provides information about the compensation paid to, earned or received during the two fiscal years ended September 30, 2019 and September 30, 2018, by the executive officers listed below (the “Named Executive Officers”).
| Executive Compensation Summary | ||||||||||||||||||||||||||||||||||||
| Name and Principal Position | Fiscal Year Sept. 30 | Fee | Bonus | Stock Awards | Option Awards | Non-Equity Incentive Plan Compensation | Non-qualified Deferred Compensation Earnings | All Other Compensation | Total | |||||||||||||||||||||||||||
| Dr. Horst A. Schmid (1) | 2019 | $ | – | (2) | $ | – | $ | – | $ | – | $ | – | $ | – | $ | 4,591 | (2) | $ | 4,591 | (5) | ||||||||||||||||
| President and | 2018 | $ | – | (2) | $ | – | $ | – | $ | – | $ | – | $ | – | $ | 9,589 | (2) | $ | 9,589 | (5) | ||||||||||||||||
| Chief Executive Officer | ||||||||||||||||||||||||||||||||||||
| Mr. Curtis Sparrow (3) | 2019 | $ | 135,666 | (4) | $ | – | $ | – | $ | – | $ | – | $ | – | $ | 3,176 | (4) | $ | 138,842 | (5) | ||||||||||||||||
| Chief Financial Officer | 2018 | $ | 140,274 | (4) | $ | – | $ | – | $ | – | $ | – | $ | – | $ | 5,164 | (4) | $ | 145,438 | (5) | ||||||||||||||||
| (1) | Dr. Horst A. Schmid has served our Company as director and Chairman of the Board since February 6, 2004. Since June 29, 2005 to present Dr. Schmid has been the President and Chief Executive Officer of our Company. |
| (2) | Portwest Investments Ltd. (“Portwest”), a company owned 100% by Dr. Horst A. Schmid, provided services as Chief Executive Officer and President to our Company for $Nil for the 2019 fiscal year and $Nil for the 2018 fiscal year. Portwest Investments Ltd. was reimbursed for expenses paid that were related to health care in the amount of $4,591 for the 2019 fiscal year and $9,589 for the 2018 fiscal year. |
| (3) | Mr. Curtis Sparrow has served our Company as director since February 6, 2004. Since February 9, 2004 Mr. Sparrow has been the Chief Financial Officer, Corporate Secretary and Treasurer of our Company. |
| (4) | Concorde Consulting, a company owned 100% by Mr. Curtis Sparrow, provided services as Chief Financial Officer to our Company for $135,666 for the 2019 fiscal year and $140,274 for the 2018 fiscal year. Concorde Consulting was reimbursed for expenses paid that were related to health care in the amount of $3,176 for the 2019 fiscal year and $5,164 for the 2018 fiscal year. |
| (5) | US$ based on the average year-end exchange rates of $0.7537 and $0.7793, respectively. |
Compensation Arrangements for Executive Officers
Our Company currently does not provide retirement benefits to its executive officers.
Our Company has entered into a contract with Concorde Consulting, a company owned 100% by Mr. Curtis Sparrow for providing services as Chief Financial Officer to our Company for Cdn$15,000 per month. As of September 30, 2019, our Company owed Concorde Consulting $Nil for services provided to our Company.
On June 20, 2013, and as herein reported under the Executive Compensation Summary table above, our Board granted Dr. Schmid and Mr. Sparrow, as directors of our Company, options to purchase 450,000 shares each of common stock at an exercise price of $0.05 per common share, one-third vesting immediately, one-third vesting on June 20, 2014, and one-third on June 20, 2015. Between June 8 to 10, 2018, five directors, two contractors and one employee of our Company, exercised a total of 3,150,000 of their option shares at an exercise price of $0.05 by way of a cashless exercise to acquire a total of 899,998 common shares of our Company, based upon the market value of our Company’s common stock of $0.07 per share on June 8, 2018, whereby 2,250,002 common shares were withheld by our Company to pay for the exercise price of the options. On June 19, 2018, one director of our Company acquired 300,000 common shares of our Company upon exercising his stock options, at an exercise price of $0.05 per common share for total gross proceeds to our Company of $15,000. The stock certificates from all of these exercises are currently held in escrow and, in addition, are restricted from trading upon final approval and release by the Management of our Company.
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Compensation of Directors
On November 28, 2005 and as amended on December 4, 2013, our Board adopted the Deep Well Oil & Gas, Inc. Stock Option Plan. The Stock Option Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Stock Option Plan is administered by our Board and permits options to acquire shares of Deep Well’s common stock to be granted to directors of our Company. The vesting of such director options will occur only if the holder of the options continues to provide services to us during the immediate annual period preceding the relevant vesting date. The options will terminate at the close of business five years from the date of grant.
On December 4, 2013, our Board appointed Mr. Pascal Nodé-Langlois as a director and in connection with the appointment our Board granted Mr. Nodé-Langlois an option to purchase 450,000 shares of common stock at an exercise price of $0.34 per share of common stock, 150,000 vesting immediately and the remaining vesting one-third on December 4, 2014, and one-third on December 4, 2015, with such options expiring on December 4, 2018. These options have since expired unexercised.
On September 19, 2014, our Board granted each of its directors, Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. Pascal Nodé-Langlois, Mr. David Roff, Mr. Curtis Sparrow and Mr. Malik Youyou, options to purchase 600,000 shares each of common stock at an exercise price of $0.38 per share of common stock, 200,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with such options expiring on September 19, 2019. These options have since expired unexercised.
On November 17, 2014, our Board appointed Mr. Colin Outtrim as a director and in connection with Mr. Outtrim’s appointment our Board granted Mr. Outtrim an option to purchase 600,000 shares each of common stock at an exercise price of $0.23 per share of common stock, 200,000 vesting immediately and the remaining vesting one-third on November 17, 2015, and one-third on November 17, 2016, with such options expiring on November 17, 2019. These options have since expired unexercised.
For the year ended September 30, 2019, our Company recorded no share-based compensation expense related to stock options (September 30, 2018 - $NIL). As of September 30, 2019, there was no unrecognized compensation cost related to option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Securities Authorized for Issuance under Equity Compensation Plans
As of September 30, 2019, with respect to shares of Deep Well common stock that may be issued under our existing equity compensation plan, see Item 5 “Equity Compensation Plan Information” of this Annual Report on Form 10-K.
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Security Ownership of Certain Beneficial Owners and Management
The following table sets forth the number and percentage of the beneficial ownership of shares of Deep Well’s outstanding common stock as of November 30, 2019 by each person or group known by us to be the beneficial owner of more than 5%, and all of our directors and executive officers individually and as a group.
| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT | ||||||||||||
Name and Address of Beneficial Owner |
Title of Class | Number of Shares Beneficially Owned (1) (2) | Percentage of Class Beneficially Owned | Nature of Beneficial Ownership | ||||||||
Malik Youyou (†) Director Sadovnicheskeya nab 69 Moscow 115035, Russia | Common | 114,856,091 | 49.81 | (3) | Direct and Indirect | |||||||
| MP West Canada SAS Beneficial Owner of 5% or more 51, Rue D’Anjou, Paris, 75008, France | Common | 45,111,778 | 19.56 | (4) | Direct | |||||||
Dr. Horst A. Schmid (†) Director and Chairman of the Board, President and Chief Executive Officer Suite 700, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada | Common | 3,651,428 | 1.58 | (5) | Direct and Indirect | |||||||
Mr. Curtis J. Sparrow (†) Director, Chief Financial Officer, Corporate Secretary and Treasurer Suite 700, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada | Common | 1,978,571 | * | 6) | Direct and Indirect | |||||||
Mr. Satya Brata Das (†) Director Suite 700, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada | Common | 1,307,381 | * | (7) | Direct and Indirect | |||||||
Mr. Said Arrata (†) Director #408, 600 Princeton Way SW Calgary, Alberta T2P 5N4 Canada | Common | 1,185,714 | * | (8) | Direct | |||||||
| Mr. David Roff (†) Director Suite 700, 10150 - 100 Street NW Edmonton, Alberta T5J 0P6 Canada | Common | 848,155 | * | (9) | Direct | |||||||
| Mr. Pascal Nodé-Langlois (†) Director c/o Parfinance SA 65 rue du Rhone 1204 Geneva, Switzerland | Common | 594,311 | * | (10) | Indirect | |||||||
| Mr. Colin P. Outtrim (†) Director 331 Rocky Ridge Dr. NW Calgary, AB T3G 4P4 Canada | Common | – | * | (11) | Direct | |||||||
| (†) All Officers and Directors as a Group | Common | 124,421,651 | 53.96 | % | Direct and Indirect | |||||||
| * | Less than 1% |
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| (1) | Under the rules of the SEC, a person or entity beneficially owns stock of a company if such person or entity directly or indirectly has, or shares the power to, vote or direct the voting, or the power to dispose or direct the disposition of such stock, whether through any contract, arrangement, understanding, relationship or otherwise. A person or entity is also deemed to be the beneficial owner of stock if such person or entity has the right to acquire either of such powers at any time within 60 days through the exercise of any option, warrant, right or conversion privilege or pursuant to the power to revoke a trust, a discretionary account or similar arrangement or pursuant to the automatic termination of a trust, discretionary account or similar arrangement. |
| (2) | Based on 230,574,603 of our Company’s common shares issued and outstanding on November 30, 2019. For calculating the percentage of beneficial ownership separately for each person, his or her options, that can be acquired within 60 days are included in both the numerator and the denominator. For the directors as a group, their collective options that can be acquired within 60 days are included in both the numerator and the denominator when calculating their group percentage ownership. |
| (3) | Mr. Malik Youyou has served the Company as director since August 20, 2008. As of November 30, 2019, Mr. Youyou beneficially owns 114,856,091 shares of our common stock, of which (i) 104,783,897 shares are held by Mr. Youyou directly; and (ii) 10,072,194 shares are held indirectly by Westline Enterprises Limited, a corporation 100% owned by Mr. Youyou. As of November 30, 2019, Mr. Youyou has a 49.81% ownership of our Company’s issued and outstanding common stock. |
| (4) | Based solely on our statement of security holder listing report received from our transfer agent on November 30, 2019, MP West Canada S.A.S. owns 45,111,778 shares of our common stock and based on this report MP West Canada S.A.S. owns 19.56% of our Company’s issued and outstanding common stock. On February 1, 2017, PT Pertamina (Persero) ("PT Pertamina") indirectly acquired MP West Canada S.A.S. as a result of the successful completion of its voluntary tender offer for all the outstanding securities, that it did not already own of Etablissementes Maurel & Prom ("M&P"). M&P is the direct beneficial owner of all of the outstanding share capital of MP West Canada S.A.S. As a result of the tender offer, PT Pertamina, through Pertamina Internasional Eksplorasi dan Produksi ("Pertamina Internasional"), has acquired a majority of the outstanding shares of M&P. Among the assets of MP West Canada S.A.S. that were acquired by PT Pertamina were 45,111,778 shares of common stock of our Company. As a result of the completion of the tender offer, PT Pertamina became the indirect beneficial owner of 45,111,778 shares of the our Company's common stock, which continue to be held of record and beneficially owned by MP West Canada S.A.S. |
| (5) | Dr. Schmid has served our Company as director and Chairman of the Board since February 6, 2004. Dr. Schmid has also served our Company as President and Chief Executive Officer since June 29, 2005. As of November 30, 2019, Dr. Schmid beneficially owns 3,651,428 shares of our Company’s common stock, of which (i) 235,714 shares are held directly; and (ii) 2,565,714 shares are held indirectly by Portwest Investments Ltd. and another 850,000 shares are held indirectly by Trans World Factors Inc., both of which are private corporations 100% owned by Dr. Schmid. As of November 30, 2019, Dr. Schmid has a 1.58% ownership of our Company’s issued and outstanding common stock. |
| (6) | Mr. Sparrow has served the Company as director and Chief Financial Officer since February 9, 2004. As of November 30, 2019, Mr. Sparrow beneficially owns 1,978,571 shares of our Company’s common stock, of which (i) 600,000 shares are held directly; and (ii) 1,378,571 shares are held indirectly by Concorde Consulting, a private corporation owned 100% by Mr. Sparrow. As of November 30, 2019, Mr. Sparrow has a 0.86% ownership of our Company’s issued and outstanding common stock. |
| (7) | Mr. Das has served our Company as director since March 8, 2011. As of November 30, 2019, Mr. Das beneficially owns 1,307,381 shares of our Company’s common stock, of which (i) 475,714 shares are held directly; and (ii) 831,667 are held indirectly by Cambridge Strategies Inc., a company 50% owned by Mr. Satya Brata Das and 50% owned by his wife. As of November 30, 2019, Mr. Das has a 0.57% ownership of our Company’s issued and outstanding common stock. |
| (8) | Mr. Arrata has served our Company as director since March 8, 2011. As of November 30, 2019, Mr. Arrata beneficially owns 1,185,714 shares of our Company’s common stock of which 1,185,714 shares are held directly. As of November 30, 2019, Mr. Arrata has a 0.51% ownership of our Company’s issued and outstanding common stock. |
| (9) | Mr. Roff has served our Company as director since April 3, 2006. As of November 30, 2019, Mr. Roff beneficially owns 848,155 shares of our Company’s common stock of which 848,155 shares are held directly. As of November 30, 2019, Mr. Roff has a 0.37% ownership of our Company’s issued and outstanding common stock. |
| (10) | Mr. Nodé-Langlois has served our Company as director since December 4, 2013. As of November 30, 2019, Mr. Nodé-Langlois beneficially owns 594,311 shares of our Company’s common stock of which 594,311 shares are held indirectly through Voltaire Group SA, a company 100% owned by Mr. Nodé-Langlois. As of November 30, 2019, Mr. Nodé-Langlois has a 0.26% ownership of our Company’s issued and outstanding common stock. |
| (11) | Mr. Outtrim has served the Company as director since November 17, 2014. As of November 30, 2019, Mr. Outtrim does not own any issued and outstanding common stock of our Company. |
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Changes in Control
Except as described below, Deep Well is not aware of any arrangement that may result in a change in control of Deep Well or its subsidiary companies.
As of November 30, 2019, and based solely on Mr. Malik Youyou’s filed Form 4s and most recent Schedule 13D, Mr. Youyou, a director of our Company, beneficially owns 114,856,091 common shares of Deep Well, representing 49.81% of Deep Well’s outstanding shares of common stock.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Transactions with Related Persons
Our Board of Directors reviews and approves all related party transactions over $10,000. The standard applied by our Board in approving any related party transaction will be to confirm that the transaction is in the best interests of our Company without regard to the interests of the related party involved in the transaction.
For the fiscal year ending September 30, 2019 and September 30, 2018, we paid Concorde Consulting, a company 100% owned by Mr. Curtis James Sparrow, $135,666 and $140,274, respectively, for consulting services provided to our Company for professional services provided to our Company as Chief Financial Officer and Corporate Secretary. Mr. Sparrow is also a director of our Company.
Mr. Malik Youyou has served the Company as director since August 20, 2008. As of November 30, 2019, Mr. Youyou beneficially owns 114,856,091 shares of our common stock, of which (i) 104,783,897 shares are held by Mr. Youyou directly and 10,072,194 shares are held indirectly by Westline Enterprises Limited, a corporation 100% owned by Mr. Youyou. As of November 30, 2019, Mr. Youyou has a 49.81% ownership of our Company’s issued and outstanding common stock.
Director Independence
See the disclosure under Item 10 “Directors, Executive Officers and Corporate Governance” of this Annual Report on Form 10-K.
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
The following table is a summary of the fees billed to us by Turner, Stone & Company, L.L.P. (“Turner Stone”) for professional services for the fiscal years as disclosed in the table below:
| Fee Category | Fees Billed in Fiscal 2019 | Fees Billed in Fiscal 2018 | ||||||
| Audit Fees | $ | 40,355 | $ | 119,505 | ||||
| Audit-Related Fees | – | – | ||||||
| Tax Fees | – | – | ||||||
| All Other Fees | – | – | ||||||
| Total Fees | $ | 40,355 | $ | 119,505 | ||||
Audit Fees
Audit fees consist of fees for services billed by Turner Stone, which is a PCAOB registered independent auditor, for the audit and review of our consolidated financial statements.
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Audit-Related Fees
None.
Tax Fees
None.
All Other Fees
None.
In addition, we were billed $5,400 Cdn which consisted of fees billed by RSM Canada, an independent third party, Canadian chartered accounting firm, relating to the preparation of our Company’s tax returns.
Audit Committee Pre-Approval Policies and Procedures
Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of our audit committee.
Our Board of Directors, acting as the Audit Committee, engaged Turner Stone as our independent registered public accounting firm, effective January 7, 2019, to audit and render an opinion on our consolidated financial statements for the fiscal year ending September 30, 2019 and to review our quarterly consolidated financial statements for the periods ending December 31, 2018, March 31, 2019 and June 30, 2019. Our Board of Directors, acting as the Audit Committee, engaged Turner Stone as our independent registered public accounting firm, effective April 30, 2018, to audit and render an opinion on our consolidated financial statements for the fiscal year ending September 30, 2018 and to review our quarterly consolidated financial statements for the periods ending December 31, 2017, March 31, 2018 and June 30, 2018. Our Board of Directors, acting as the Audit Committee, pre-approved all audit and non-audit services provided by Turner Stone for the fiscal years ending September 30, 2019 and September 30, 2018. Further our Board of Directors, acting as the Audit Committee, considered the nature and amount of the fees billed by Turner Stone, and believes that the provision of the services for activities unrelated to the audit of our September 30, 2019 and September 30, 2018 financial statements is compatible with maintaining the independence of Turner Stone.
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| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
Financial Statements filed with this Annual Report
The following listed financial statements and report of independent registered public accounting firm are filed as part of this Annual Report (see disclosure under Item 8 “Financial Statements and Supplementary Data” of this Annual Report for further information)
| 1. | Consolidated Balance Sheets for September 30, 2019 and 2018. |
| 2. | Consolidated Statements of Operations for the years ended September 30, 2019 and 2018. |
| 3. | Consolidated Statements of Shareholders’ Equity for the period from September 30, 2019 to September 30, 2018. |
| 4. | Consolidated Statements of Cash Flows for the years ended September 30, 2019 and 2018. |
| 5. | Notes to the Consolidated Financial Statements. |
| 6. | Turner, Stone & Company, L.L.P. Report of Independent Registered Public Accounting Firm. |
Financial Statement Schedules filed with this Annual Report
None.
Exhibits
The following Exhibits have been or are being filed herewith and are numbered in accordance with Item 601 of Regulation S-K:
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| * | Management contract or compensatory plan or arrangement. |
| ITEM 16. | FORM 10-K SUMMARY |
Not applicable.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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 | ||
| Chairman of the Board | ||
| Date | January 13, 2020 | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| By | /s/ Horst A. Schmid | |
| Dr. Horst A. Schmid | ||
| Chief Executive Officer and President | ||
| (Principal Executive Officer) | ||
| Date | January 13, 2020 | |
| By | /s/ Curtis J. Sparrow | |
| Mr. Curtis James Sparrow | ||
| Chief Financial Officer | ||
| (Principal Financial Officer) | ||
| Date | January 13, 2020 |
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