DEEP WELL OIL & GAS INC - Annual Report: 2016 (Form 10-K)

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, 2016

or

o      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)

Registrant’s telephone number, including area code: (780) 409-8144

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o 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 o 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 o No þ

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes o No þ

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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.

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. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o 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, 2016 was approximately $2.4 million.

As of March 8, 2018, the Issuer had outstanding approximately 229,374,605 shares of common stock, $0.001 par value per share.

TABLE OF CONTENTS

GLOSSARY AND ABBREVIATIONS

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.

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 = 0.404685 hectares. 1 hectare = 2.471054 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.

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$ 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.

CURRENCY EXCHANGE RATES

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, based on the noon rates of exchange for such periods as reported by Oanda and or Bank of Canada.

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”.

PART I

We are an emerging independent junior oil sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base 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 or www.DWOG.com. The contents of our website are not part of this annual report on Form 10-K for the fiscal year ended September 30, 2016 (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. (“Deep Well Alberta”), incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005.

Business Development

We are engaged in the identification, acquisition, exploration and development of oil sands prospects. Our main objective is to develop our oil sands lease holdings located in the Peace River oil sands area of North Central Alberta, Canada.

On July 30, 2013, we entered into a Steam Assisted Gravity Drainage Demonstration Project Joint Operating Agreement (the “SAGD Project”) to jointly participate in the Alberta Energy Regulator (“AER”) approved SAGD Project on a portion of one section of land where we have a 25% working interest (post Farmout Agreement as defined below). The SAGD Project is located in section 30-91-12W5 of our Peace River oil sands properties located in North Central Alberta, Canada (also known as our Sawn Lake oil sands properties).

On July 31, 2013, we entered into a farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund our portion of the costs of the SAGD Project. 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 as set out in the Farmout Agreement in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the execution of the Farmout Agreement. The Farmee is also required to provide funding to cover monthly operating expenses of our Company provided that such funding shall not exceed $30,000 per month.

For more information regarding our SAGD Project see “Present Activities - Peace River Oil Sands, Alberta Canada (Sawn Lake Properties)” under Item 2 “Properties” of this Annual Report on Form 10-K.

Effective September 25, 2014, we entered into a Purchase and Sale agreement with Classic Energy Inc. (“Classic”), pursuant to which we acquired Classic’s 20% working interest in five sections on one Sawn Lake oil sands lease where we already own working interests. In connection with, this acquisition, as of September 25, 2014, we have increased our net acres in our Sawn Lake oil sands properties from 33,463 to 34,096 net acres.

Principal Product

We are engaged in the identification, acquisition, exploration and development of oil sands prospects. At this time, our primary interest and immediate focus is the development of our oil sands property in the Peace River oil sands area located in North Central Alberta, Canada, using thermal recovery technologies. 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 a 90% working interest in 51 sections on six oil sands leases and a 100% working interest in five sections on one oil sands lease in the Peace River oil sands area of Alberta, where we are the operator. In addition, we have a 25% working interest, since execution of the Farmout Agreement, in another 12 sections on two oil sands leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous and cover 43,015 gross acres (17,408 gross hectares) with our Company having 34,096 net acres (13,798 net hectares). The focus of our Company’s operations is to exploit 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 being trucked and sold to marketing facilities in the Peace River area of Alberta. Primarily because of the low-price environment at the time, a majority of the Joint Venture partners voted to temporarily suspend operations of 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.

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 oil sands leases covering 23,405 gross acres (9,472 gross hectares) located within our Sawn Lake properties (the “Purported 6.5% Royalty”). Nearshore claimed a 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 this Purported 6.5% Royalty to other parties.

On March 18, 2014 and June 27, 2014, through Northern, we entered into and subsequently closed two Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and Transfer Agreements (collectively the “Agreements”), with one of our joint venture partners (our “JV Partner”) and one related party, Mr. Malik Youyou, who is a director and majority shareholder of our Company, (the “Related Party”) whereby we acquired and cancelled 5.5% of the disputed Purported 6.5% Royalty claim on certain lands owned by us. Our counsel and the vendor’s counsel negotiated the terms and conditions of the Agreements. Pursuant to the terms and conditions of the Agreements, we paid the following consideration:

Although we continue to deny the validity of the Purported 6.5% Royalty, we determined that it was in the best interests of our shareholders to come to an arrangement to acquire and cancel most of the Purported 6.5% Royalty to prevent a potential encumbrance over our land and the possibility of future litigation resulting from these alleged royalty claims.

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.

The North American Free Trade Agreement. The North American Free Trade Agreement (“NAFTA”) is the largest free trade region in the world. To comply, Canada must ensure that export restrictions do not (i) reduce the proportion of energy exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements. This agreement is presently being renegotiated.

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. The governments of each province and the federal government of Canada have enacted legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. 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.

Effective January 1, 2009, 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.

The Government of Alberta receives royalties on the production of crude oil and natural gas from lands where they own the mineral rights. The Government of Alberta released a royalty review report on January 29, 2015. The report recommends no changes to existing oil sands royalty rates but recommended further government-industry consultation on administrative aspects of the oil sands royalty regime. The royalty review report recommended a modernization of Alberta’s conventional oil and gas royalty regime but did not provide details. The changes proposed to conventional oil and gas royalties will require further consultation between industry and government to fully understand their impacts. These changes to the Alberta provincial royalty structure could have a significant impact on our Company’s financial condition, results of operations and cash flows. An increase in the government royalty rates in Alberta may make our existing operations uneconomic.

Research and Development

We had no material scientific research and development costs for the fiscal years ended September 30, 2016 and 2015.

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 certain oil and gas industry operations. In addition, 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.

Effective July 1, 2007, Alberta was the first province in Canada to develop legislation regulating greenhouse gas emissions that requires large industrial emitters to report their emissions and take actions to make mandatory reductions. This legislation, the Specified Gas Emitters Regulation (“SGER”) under the Climate Change and Emissions Management Act has set requirements for facilities that emit. more than 100,000 tonnes of greenhouse gases a year to reduce baseline emissions intensities by 12 per cent. The oil sands sector accounts for roughly one-quarter of Alberta’s annual emissions. Companies have four choices to meet their reductions: (i) they can make operating improvements to their operations that will result in greenhouse gas emission reductions; (ii) they can purchase Alberta based offset credits; (iii) they can contribute to the Climate Change and Emissions Management Fund; or (iv) they can purchase or use emission performance credits (“EPCs”). EPCs are generated by facilities that have gone beyond the 12% mandatory intensity reduction and can be banked for future use or sold to other facilities that need to meet the reduction target. And, in November, 2015, the government of Alberta announced its climate leadership plan (the “CLP”) to reduce carbon emissions. The federal government has announced that provinces in Canada must enact an emissions reduction plan or Ottawa will impose a federal carbon tax in 2018. With the CLP, the government is launching an Alberta-first strategy designed specifically for Alberta’s own unique economy. The five key strategies that the government of Alberta will implement to address climate change under its CLP plan are: (i) implementation of a new carbon price on greenhouse gas emissions and ending pollution from coal-generated electricity with a complete phase-out of coal-fired sources of electricity by 2030; (ii) an Alberta economy-wide price on GHG emissions of $30/tonne will be applied to oil sands facilities; (iii) capping oil sands emissions to a province-wide total of 100 megatonnes per year, with certain exceptions for cogeneration power sources and new upgrading capacity; (iv) reducing methane emissions from oil and gas activities by 45 percent by 2025; and (v) developing more renewable energy.

On June 18, 2009, the government of Canada passed an Environmental Enforcement Act (the “EEA”). The EEA was created to strengthen and amend nine existing statutes that relate to the environment and to enact provisions in respect of the enforcement of certain statutes that relate to the environment. The EEA amended various enforcement, offence, penalty and sentencing provisions to discourage offences under the EEA by setting minimum and maximum fines, in particular for serious offences. The EEA also provided enforcement officers new powers to investigate cases and grants courts new sentencing authorities that ensure penalties reflect the seriousness of the pollution and wildlife offences. The EEA also expands the authority to deal with environmental offenders by: (i) specifying aggravating factors such as causing damage to wildlife or wildlife habitat, or causing damage that is extensive, persistent or irreparable; (ii) providing fine ranges that are higher for corporate offenders than for individuals; (iii) doubling fine ranges for repeat offenders; (iv) authorizing the suspension and cancellation of licenses, permits or other authorizations upon conviction; (v) requiring corporate offenders to report convictions to shareholders; and (vi) mandating the reporting of corporate offences on a public registry.

In December 2015, Canada and 194 other countries that are members of the United Nations Framework Convention on Climate Change met in Paris, France and signed the Paris Agreement to fight climate change. The stated objective of the Paris Agreement is to hold the increase in global average temperature to well below 2 degrees Celsius above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 degrees Celsius. Additionally, the Paris Agreement contemplates that, by 2020, the parties will develop a new market-based mechanism related to carbon trading. The government of Canada stated, at that time, that it will develop and announce a Canada-wide approach to implementing the Paris Agreement in early 2016. On October 5, 2016, the House of Commons approved Prime Minister Justin Trudeau’s October 3, 2016 motion to impose a carbon tax starting in 2018. Pursuant to the Prime Minister’s plan, the federal government will set a minimum price of $10 per tonne of carbon emissions in 2018 and the price will rise by $10 each year to $50 per tonne in 2022. The provinces and territories can choose to implement a direct carbon tax or adopt a cap-and-trade system which meets or exceeds the federal minimum price. The federal government will impose a direct carbon tax in any provinces or territories which fail to have a price or cap-and trade system is in place by 2018.

On April 9, 2016, the Canadian government published draft regulations providing details on the implementation of the Environmental Violations Administrative Monetary Penalties Act ("EVAMPA"), together with a Policy Framework, which outlines the basic policy framework of the Administrative Monetary Penalties ("AMP") system at Environment and Climate Change Canada ("Environment Canada"). These draft regulations lead the way to the implementation of a federal AMP regime, more than five years after the adoption of the EEA on June 18, 2009. AMPs are enforcement measures and are intended to encourage compliance with environmental regulations. For industries, this new regime, if adopted, could represent a new challenge, since Environment Canada would now have a new tool to use to ensure the compliance with many federal environmental laws.

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.

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 Crown 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.

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, 2016 and 2015 we reported net losses of $554,374 and $1,884,667 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 2016 and 2015 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 and to drill exploratory wells. 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 spring-break up, 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.

Our Interests Are Held In The Form Of Leases That We May Be Unable To Retain. Our Sawn Lake oil sands properties are held as leases with working interests ranging from 25% to 100%. 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 government of Alberta tenure guidelines. If we fail to meet the specific requirements of the lease regarding delay or non-payment of rental payments or we fail to meet the minimum level of evaluation, some or all of our leases may terminate or expire. There can be no assurance that any of the obligations required to maintain each lease will be met. The termination or expiration of our leases or the working interests relating to 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 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 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 in 51 sections on six oil sands leases, a 100% working interest in five sections on one oil sands lease, where we are the operator of the 90% and 100% leases. We also have a 25% working interest in an additional 12 sections on two oil sands leases where one of our joint venture partners is the operator. These nine oil sands leases, which are all contiguous, cover 43,015 gross acres (17,408 gross hectares) where we currently have 34,096 net acres (13,798 net hectares). All nine oil sands leases are located in the Peace River oil sands area of Alberta, Canada. Our lack of operational control of the 12 sections currently not operated by us means we are exposed to the following possibilities:

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. Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Since aboriginal peoples have filed a claim claiming aboriginal title or rights to the lands on which some of our properties are located, and if such a claim is successful, it could have a material adverse effect on our operations.

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 must 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, the applicant must address all questions, objections, and concerns regarding the proposed development project 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.

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. economic environment, weather conditions, the availability 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 could 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.

We Could Be Subject To SEC Penalties If We Do Not File All Of Our SEC Reports. We have not timely filed this current Annual Report on Form 10-K, and the subsequent Annual Report of Form 10-K for the year ended September 30, 2017, and subsequent quarterly reports on Form 10-Q as 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.

None.

Office Leases

We lease and maintain office space in Edmonton, Alberta for corporate and administrative operations. This lease will expire on June 30, 2019.

Oil and Gas Properties

Acreage

Currently, we have a 90% working interest in 51 sections on six oil sands leases, a 100% working interest in five sections on one oil sands lease, and a 25% working interest in an additional 12 sections on two oil sands leases in the Peace River oil sands area of Alberta, all of these sections are contiguous. These nine oil sands leases cover 43,015 gross acres (17,408 gross hectares). Of the 68 contiguous sections on nine oil sands leases, one of our joint venture partners is the operator of 12 sections on two oil sands leases where we have a 25% working interest since the execution of the Farmout Agreement, and we are the operator on 56 sections on seven 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 summarize, by geographic area, our gross and net developed and undeveloped Peace River oil sands rights under lease as of September 30, 2016:

A developed acreage is considered to mean those acres spaced or assignable to productive wells, a gross acre is an acre in which a working interest is owned, and 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. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not that acreage contains proven reserves, but does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can generally retain our interest in undeveloped acreage by engaging in drilling activity that establishes commercial production sufficient to maintain the leases, or by paying delay rentals during the remaining primary term of such a lease. The oil sands leases in which we have an interest are for a primary term of 15 years, and if we meet the Minimum Level of Evaluation (“MLE”) as set out by the government of Alberta oil sands tenure guidelines we can continue these leases beyond their primary term for an indefinite period. For further information, see Oil and Gas Properties Note 3 in the notes to our consolidated financial statements contained herein in this Annual Report on Form 10-K.

Our current developed and undeveloped oil sands acreage as of November 30, 2017, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until we extend the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of our nine oil sands leases are as follows:

Delivery Commitments

We are not subject to any obligations under existing delivery commitment contracts or agreements calling for the provision of fixed and determinable quantities of oil and gas.

Disclosure of Reserves

We did not have our properties assessed and evaluated for reserves and resources as of September 30, 2016.

Under current SEC standards, “Proved Reserves” are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, 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.

Under current SEC standards, the term “Reasonable Certainty” if deterministic methods are used, implies a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.

Under current SEC standards, “Reliable Technology” is a grouping of one or more technologies (including computational methods) that have been field tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated proved reserves, if any, we employ in-situ technologies that have been demonstrated to yield results in the oil sands with consistency and repeatability. The technical data used in the estimation of our proved reserves, if any, include, but are not limited to, electrical logs, core analyses, geologic maps and available downhole and production data, seismic data, well test data and SAGD project results. Reserves, if any, attributable to our producing wells which have limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity.

The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of our reserves, if any, and future cash flows are based on various assumptions and are inherently imprecise.

There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more data about our properties becomes available.

Estimates of probable and possible reserves are inherently imprecise. When producing an estimate of the amount of oil that is recoverable from a particular reservoir, probable reserves are those 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. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Estimates of probable and possible reserves are by their nature much more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk.

Preparation of Reserves Estimates and Reserves Evaluation

DeGolyer did not assess and evaluate our properties for reserves and resources as of September 30, 2016. Our properties were previously assessed and evaluated, as of September 30, 2015, for reserves and resources by DeGolyer and MacNaughton Canada Limited (“DeGolyer”) in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by DeGolyer met 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 properties were assessed and evaluated, as of September 30, 2015, by independent examination and evaluation of our production data, reservoir pressure data, logs, geological data, and offset analogies. DeGolyer was provided full access to complete and accurate information pertaining to our properties, and to all applicable personnel of our Company. DeGolyer’s independent evaluation of our properties for reserves, as of September 30, 2015, was supervised Ms. Nahla Boury, President of DeGolyer. Ms. Boury is a registered professional engineer in Alberta, Canada and has over 25 years of oil and gas industry experience and 21 years of application evaluation experience. Our Board appointed a reserves and resources committee consisting of four Board members. The reserves and resources committee members are Mr. Said Arrata, Mr. David Roff, Mr. Colin Outtrim and Mr. Curtis James Sparrow. Our reserves estimates, if any, and process for developing such estimates are reviewed by our current reserves and resources committee and approved by our management. Our 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 management is ultimately responsible for reserve estimates, if any, and reserve disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

Estimates of oil and natural gas reserves, if any, are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. The process also requires assumptions relating to availability of funds and timing of capital expenditures for development of our proven undeveloped reserves, if any. These reports should not be construed as the current market value of our past assigned reserves. Because of the uncertainties inherent in the interpretation of this data, we cannot be certain that reserves, if any, will ultimately be realized. Our actual results could differ materially.

Third Party Reports

DeGolyer did not assess and evaluate our properties for reserves and resources as of September 30, 2016.

Proved Undeveloped Reserves

DeGolyer did not assess and evaluate our properties for reserves and resources as of September 30, 2016. As of September 30, 2015, DeGolyer did assess and evaluate our properties for reserves and resources. Our Company reported no proved reserves as of September 30, 2015.

Reserves Reported to Other Agencies

DeGolyer did not assess and evaluate our properties for reserves and resources as of September 30, 2016. Our Company is required to file a Statement of Reserves Data and Other Oil and Gas Information on Form 51-101F1 and any amendments with the Alberta Securities Commission pursuant to National Instrument 51-101 – Standard of Disclosure for Oil and Gas Activities, in which we reported no net oil reserves prepared in accordance with the Canadian Oil and Gas Evaluation Handbook (“COGEH”).

Oil and Gas Production, Production Prices and Production Costs

On September 16, 2014, the first SAGD well pair started producing oil from our joint Sawn Lake oil sands properties. We received our first revenue late in September of 2014 from the sales of our produced oil. As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of the Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016. The following table discloses our 25% working interest share of production and average sales price for the last three fiscal years:

⁽¹⁾ First production began September 16, 2014.

⁽²⁾ Our Company’s working interest share before royalties.

⁽³⁾ Currently all of our operating costs from the SAGD Project are being paid by the Farmee under the terms of the Farmout Agreement

Productive Wells

The following table sets forth our gross and net productive oil wells as of September 30, 2016:

⁽¹⁾ SAGD producer well

As of the fiscal years ended September 30, 2016 and 2017 all of our producing wells were still shut-in.

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, 2017, 2016, 2015 and 2014.

⁽¹⁾ Our 25% working interest in one SAGD producer well.

⁽²⁾ Our 25% working interest in one SAGD steam injection well, one water source well and one disposal well.

Present Activities – Peace River Oil Sands, Alberta Canada (Sawn Lake Properties)

We recently participated in drilling one core well in August of 2017. The well was drilled to a total depth of 681 meters. The results of this well will be used for an application for continuation of the mineral rights on one of our oil sands leases.

Currently we have no wells in the process of being drilled. However, we have 11 exploratory wells on our Sawn Lake oil sands properties that we previously drilled and completed which are currently suspended. And in addition to the 11 exploratory wells, we also have one SAGD well pair which is also temporarily shut-in.

As previously disclosed, on July 30, 2013, we are participating in a SAGD Project with our joint venture partners, whereby our Company holds a 25% working interest. The SAGD Project consists of one SAGD well pair drilled to an approximate 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 was producing from September to the end of February 2016. In January and February of 2016, production from the SAGD Project reached a steady state average of 615 barrels per day (“bopd”), on a 100% basis (154 bopd net to us), with an average SOR of 2.1 from the one SAGD well pair. The early production results of the current SAGD Project successfully confirmed the capability of the Bluesky reservoir to produce using thermal recovery technology. However, at that time, given the low-price environment for bitumen, a majority of our Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016.

In early May of 2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would potentially increase the 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). It is anticipated that only five SAGD well pairs will be needed to achieve this production level. The AER approval for the expansion of the existing SAGD Project was granted on December 14, 2017. Currently, the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake. The SAGD Project expansion is dependent on, numerous factors including but not limited to, the approval of the joint venture partners.

As previously disclosed, on July 31, 2013, we entered into the Farmout Agreement. In accordance with the Farmout Agreement, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the execution of the Farmout Agreement. The Farmee 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. As required by the Farmout Agreement, as of November 30, 2017, the Farmee has since reimbursed our Company and/or paid the operator approximately $21.5 million ($26.7 million Cdn) in total for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project. These costs include the capital costs of the drilling and completion of one SAGD well pair; the purchase and transportation of equipment; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source 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; some front end costs for the expansion; and the start-up operating expenses associated with the steaming and production of one SAGD well pair.

Currently, we have in place joint operating agreements (our “Joint Operating Agreements”) with our joint venture partners to manage the operations of our joint oil sands leases. Under these agreements our joint oil sands leases were evaluated seismically, geologically and by drilling to establish the continuity and the distribution of the crude bituminous-bearing Bluesky reservoir zone across our joint lands. The development progress of our properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can and often do delay development of similar projects. Because of these and other factors, our oil sands project can take significantly longer to complete than regular conventional drilling programs for lighter oil. To date, our geological, engineering and economic studies lead us to believe that our working interest can support future full profitable commercial production.

In August 2013, we received approval from the AER for our HCSS Project application. It is anticipated that we will develop a thermal demonstration project on our properties followed by a commercial expansion project on one half section of land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently have a 90% working interest. This application, submitted in early 2012, was an application to modify our previously approved in-situ demonstration project for a well to test thermal production on our Sawn Lake oil sands leases. This modification changed the vertical CSS well earlier approved, into a thermal recovery project to test two wells that use a horizontal application of CSS. We received the final performance results and revised reservoir modeling studies from our current SAGD Project which will be used to fine-tune our HCSS Project facility design before we initiate start-up operations on the half of a section of land where we plan to drill two horizontal wells to test the use of HCSS technology. We performed an environmental field study and surveyed the proposed location of our planned HCSS Project site and recently received AER approval for the surface wellsite and access road for this project.

We are not aware of any material pending legal actions against our Company.

Not applicable.

PART II

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:

Holders of Record

As of February 28, 2017, we had approximately 169 holders of record of our shares of common stock. Our Company estimates that investment dealers and other nominees are the record holders for approximately 2,121 beneficial holders.

Dividends

We have not paid cash dividends since inception. We intend to retain all of our earnings, if any, for use in our business and do not anticipate paying any cash dividends in the foreseeable future. The payment of any future dividends will be at the discretion of the Board of Directors (our “Board”) and will depend upon a number of factors, including future earnings, the success of our business activities, capital requirements, the general financial condition and our future prospects, general business conditions and such other factors as our Board may deem relevant.

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of September 30, 2016 with respect to shares of Deep Well’s common stock that may be issued under our existing equity compensation plans.

⁽¹⁾ On June 20, 2013, our Board granted our directors Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. David Roff, Mr. Curtis Sparrow and Mr. Malik Youyou, options to purchase 450,000 shares each of common stock at an exercise price of $0.05 per share of common stock, with one-third vesting immediately, one-third vesting on June 20, 2014, and one-third vesting on June 20, 2015, each with a five-year life from the original grant date. And on June 20, 2013, our Board also granted two consultants, Portwest Investments Ltd. and Concorde Consulting, options to purchase 1,000,000 shares each of common stock at an exercise price of $0.05 per share of common stock, with one-half vesting immediately and one-half vesting on June 20, 2014, each with a five-year life from the original grant date. And on June 20, 2013, our Board also granted one employee of our Company, options to purchase 150,000 shares of common stock at an exercise price of $0.05 per share of common stock, with one-third vesting immediately, one-third vesting on June 20, 2014, and one-third vesting on June 20, 2015, with a five-year life from the original grant date. On October 28, 2013, the our Board granted a contractor an option to purchase 250,000 shares of common stock at an exercise price of $0.30 per share of common stock, all vesting immediately, with a five-year life, for his services in connection with the Farmout Agreement. On December 4, 2013, the Board appointed Mr. Pascal Nodé-Langlois to its Board and in connection with this appointment the Board granted Mr. Nodé-Langlois an option to purchase 450,000 shares each 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 a five-year life. On September 19, 2014, the Board granted Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. Pascal Node-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 a five-year life. On September 19, 2014, the Board granted two consultants, Portwest Investments Ltd. and Concorde Consulting, an option to purchase each 1,200,000 shares each of common stock at an exercise price of $0.38 per share of common stock, 600,000 vesting immediately and remaining vesting on September 19, 2015. On September 19, 2014, the Board granted one employee an option, expiring five years after the date of grant, to purchase 180,000 shares each of common stock at an exercise price of $0.38 per share of common stock, with the option to purchase 60,000 shares vesting immediately and the option to purchase 60,000 shares on September 19, 2015, and another 60,000 shares on September 19, 2016. 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.

⁽²⁾ Based on 229,374,605 issued and outstanding shares as at September 30, 2016. 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 Note 12 in the notes to our consolidated financial statements contained herein.

On March 23, 2016, 900,000 option shares that were previously issued on March 23, 2011 expired unexercised.

Performance Graph

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.

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, 2016.

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.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. This discussion includes forward-looking statements that reflect our current views with respect to future events and financial performance that involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding – Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors” and “Environmental Laws and Regulations” disclosed in this Annual Report.

Our consolidated financial statements and information are reported in US dollars and are prepared based upon US generally accepted accounting principles (“US GAAP”). On March 5, 2018, the daily rate of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.7706 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 emerging independent junior oil sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base where we have working interests ranging from 25% to 100% in the Peace River oil sands area of Alberta, Canada. Our principal office is located at Suite 700, 10150 - 100 Street, Edmonton, Alberta, Canada T5J 0P6, our telephone number is (780) 409-8144, and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com or www.DWOG.com. The contents of our website are not part of the annual report on Form 10-K for the fiscal year ended September 30, 2016.

Results of Operations

Since the inception of our current business plan, our operations have consisted of various exploration and start-up activities relating to our properties, including the acquisition of lease holdings, raising capital, locating joint venture partners, acquiring and analyzing seismic data, complying with environmental regulations, providing project management, drilling, testing and analyzing of wells to define our oil sands reservoir, and development planning of our Alberta Energy Regulatory (“AER”) approved thermal recovery projects.

During the fourth quarter of our 2015 fiscal year, our Company voluntarily changed its method of accounting for our oil and gas properties from the successful efforts method to the full cost method of accounting. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the full cost method. We believe that the full cost method is preferable as it better reflects the results of our Company’s operations and the economics of exploring for and developing our non-traditional long life oil sands assets in the Peace River oil sands area in Alberta. See Note 2 - Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K. The following table sets forth summarized financial information:

First production from our present joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began on September 16, 2014. As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of our Company’s Joint Venture partners voted to temporarily suspend operation of the SAGD Project at the end of February 2016. For the fiscal year ending September 30, 2016, oil revenue totaled $151,432, before royalties. For the year ending September 30, 2016, the volume of oil delivered was 19,156 barrels net to our Company, before royalties, with an average oil sales price of $7.91 per barrel ($10.48 per barrel Cdn). We only produced oil for 5 months during the current fiscal year prior to the shutting in production at the end of February 2016. For the fiscal year ending September 30, 2015, oil revenue totaled $609,575, before deduction of royalties. For the year ending September 30, 2015, the volume of oil delivered was 25,737 barrels net to our Company, before royalties, with an average oil sales price of $23.68 per barrel ($29.00 per barrel Cdn). The realized sales price of our oil is discounted for diluent, blending, trucking, pipeline access and additional treating costs compared to the West Texas Intermediate (“WTI”) benchmark price, but paid in Canadian dollars. While oil prices remained low in 2015 and in 2016, the Canadian dollar weakened and in 2015 and 2016 offset some of the lower WIT price impact. Our net operating margin after operating expenses is zero since at this time any negative operating margins are reimbursed to us under the farmout agreement we entered into on July 31, 2013 (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund our share of the current SAGD Project. Transportation costs are included in these operating costs. Therefore, the total share of the capital costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $21.5 million ($26.7 million Cdn) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project as of November 30, 2017. These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator (“OTSG”), production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; and the operating expenses associated with the steaming and production of the one SAGD well pair. 

Existing SAGD Project Surface Facility located on Section 7-30-91-12W5.

For the year ended September 30, 2016, our general and administrative expenses decreased by $1,332,921 compared to the year ended September 30, 2015. This was a 73.2% decrease from the 2015 fiscal year which was primarily due to a decrease of $878,573 in share based compensation expense and a decrease of $254,261 in foreign exchange losses. 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 operational expenses.

For the year ended September 30, 2016, our share based compensation expense was $237,971 compared to $1,116,545 for the year ended September 30, 2015. After adjusting for the non-cash items, mainly share based compensation and foreign exchange, our general and administrative expenses were $586,134 for the year ended September 30, 2016 compared to $816,314 for the year ended September 30, 2015.

For the year ended September 30, 2016, our depreciation and accretion expense decreased by $12,220 compared to the year ended September 30, 2015, 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, 2016, our rental and other income decreased by $13,659 compared to the year ended September 30, 2015, which was primarily due to a decrease of office rental income.

As a result of the above transactions, our net loss and loss from operations for the year ended September 30, 2016 decreased by $1,330,293 compared to the year ended September 30, 2015. As discussed above this decrease was primarily due to the decrease in share based compensation expense and foreign exchange losses.

Operations

In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the execution of the Farmout Agreement. The Farmee is also required to provide funding to cover monthly operating expenses of our Company provided that such funding shall not exceed $30,000 per month. In addition, the Farmee had the option, exercisable up to December 31, 2015, to commit an additional $110,000,000 of financing to the development of our Company’s Sawn Lake oil sands properties, to obtain an additional working interest of 45% to 50% in the remaining 56 sections of land where we have working interests ranging from 90% to 100%. The Farmee did not exercise their option.

The first SAGD well pair established that SAGD thermal technology is effective in producing oil from the Bluesky reservoir formation at Sawn Lake. Our SAGD Project also provided valuable productivity information about the Bluesky reservoir. The following graph sets out the production levels since the project started producing. In October of 2015, the operator began steam rate trials to optimize production while lowering the steam injection rate, thereby lowering the steam to oil ratio (“SOR”). The SOR is reflective of the amount of steam needed to produce one barrel of oil. The average SOR for January and February of 2016 was 2.1. These production numbers along with the corresponding SORs compare favorably to analogous reservoirs in thermal recovery projects that we are monitoring and using as a basis of comparison. The capital costs of the existing SAGD Project steam plant facility, with pipelines and one SAGD well was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest basis, of which our share is covered under the Farmout Agreement (these capital costs do not include the start-up operating expenses to initiate oil production from the SAGD well pair). As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of our Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016. 

The current SAGD Project has:

The first SAGD well pair, for the SAGD Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection commenced in May 2014 and production started in September of 2014. Production from this one SAGD well pair and increased significantly over the 18-month period it produced. In January and February of 2016 production from the SAGD Project reached a steady state averaging 615 bopd, on a 100% basis (154 bopd net to us), with an average SOR of 2.1 from one SAGD well pair. It is expected that a reactivation of the existing SAGD Project facility and current SAGD well pair will be part of the potential commercial expansion along with the previously AER approved second SAGD well pair. In early May of 2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would potentially increase the operation for up to a total of eight SAGD well pairs. The amended application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be operating to achieve this production level. The expanded facility will be designed to handle up to 3,200 bopd. The AER approval for the expansion of the existing SAGD Project was granted on December 14, 2017. While the joint venture has not yet approved to expand the SAGD Project, currently, the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake. Expanding the SAGD Project would be a significant step towards establishing commercially viability at Sawn Lake on a larger scale.

Oil sales terminal at our joint SAGD Project

We also recently participated in drilling one core well in August of 2017. The well was drilled to a total depth of 681 meters. The results of this well will be used for an application for continuation of the mineral rights on one of our oil sands leases.

In August 2013, we received approval from the AER for our horizontal cyclic steam stimulation project (“HCSS Project”) application. It is anticipated that we will develop a thermal demonstration project on our properties followed by a commercial expansion project on one half section of land located on section 10-92-13W5 of our Sawn Lake oil sands properties where we currently have a 90% working interest. We have since received the final performance results and revised reservoir modeling studies from our SAGD Project which will be used to fine-tune our HCSS Project facility design before we initiate start-up operations on the half of a section of land where we plan to drill two horizontal wells to test the use of HCSS technology. We performed an environmental field study and surveyed the proposed location of our planned HCSS Project site and recently received AER approval for the surface wellsite and access road for this project.

Currently, we have a 90% working interest in 51 sections on six oil sands leases and a 100% working interest in five sections on one oil sands lease in the Peace River oil sands area of Alberta, where we are the operator. In addition, we have a 25% working interest in another 12 sections on two oil sands leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous and cover 43,015 gross acres (17,408 gross hectares) with our Company having 34,096 net acres (13,798 net hectares) as shown in the map below. The development progress of our properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can, and often, do delay development of similar projects. Because of these and other factors, our oil sands project could take significantly longer to complete than regular conventional drilling programs for lighter oil.

Liquidity and Capital Resources

As of September 30, 2016, our total assets were $23,166,967 compared to $23,684,393 as of September 30, 2015. This decrease of $517,426 was due to a decrease of $669,350 in our current assets, which was primarily due to cash used for general and administrative expenses and a decrease in our accounts receivable.

For the year ended September 30, 2016, 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, 2016 was necessary. No write-downs of our unproven oil sands properties were recorded in the year ended September 30, 2015. However, our unproven oil sands properties may be at risk for future ceiling test write-downs. It is potentially possible that continued declines in oil prices and possible changes to our Company’s drilling plans in response to lower prices or increases in drilling or operating costs could result in other additional write-downs to our Company’s unproven oil sands properties.

As of September 30, 2016, our total liabilities were $502,508 compared to $703,531 as of September 30, 2015. This decrease of $201,023 in our total liabilities was primarily the result of our payment for outstanding accounts payable to the operator of the SAGD Project for operating expenses, which was reimbursed to us by the Farmee, in accordance with the terms of the Farmout Agreement.

Our working capital is as follows.

As of September 30, 2016, our Company had working capital of $1,406,475 compared to our working capital of $1,848,876 as of September 30, 2015. This decrease is mainly due to cash used for general and administrative expenses. As of September 30, 2016, we had no long-term third-party debt other than our estimated asset retirement obligations on our oil and gas properties. On July 31, 2013, we entered into the Farmout Agreement to fund our share of the costs of our joint SAGD Project. As of September 30, 2016, we had a decrease of $226,949 in our accounts payable compared to the prior fiscal year.

As reported on our Consolidated Statement of Cash Flows under “Operating Activities”, for the year ending September 30, 2016, our net cash used in operating activities was $189,808 compared to $386,168 for the year ended September 30, 2015. This decrease of $196,360 was primarily the result of cash used for general and administrative expenses.

As reported on our Consolidated Statement of Cash Flows under “Investing Activities”, we had an increase of $4,446 in the investment in our oil and gas properties and a decrease of $33,775 in our long term investments for the year ended September 30, 2016, compared to the year ended September 30, 2015.

As reported on our Consolidated Statement of Cash Flows under “Financing Activities”, for the year ended September 30, 2016, there was no cash inflow or outflow in financing activities. For the year ended September 30, 2015, we received $5,000 from one shareholder in exchange for 47,618 shares of our common stock upon the exercise by that shareholder of warrants at an exercise price of $0.105 per common share.

Our cash and cash equivalents for the year ending September 30, 2016 were $1,400,922 compared to $1,786,270 in the year ending September 30, 2015. This decrease of $385,348 in cash was primarily due to general and administrative expenses. As of September 30, 2016, we had no long-term debt other than our estimated asset retirement obligations on our oil and gas properties.

Our current SAGD Project operating costs are covered by the Farmout Agreement. For our long-term operations, we anticipate that, among other alternatives, we may raise funds during the next twenty-four months through sales of our equity securities or debt. We also note that if we issue more shares of our common stock, our stockholders will experience dilution in the percentage of their ownership of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so, we may be forced to delay our business plans until adequate funding is obtained.

Full Cost Method of Accounting

Our Company’s Board adopted the full cost method of accounting for its oil sands activities effective July 1, 2015. Our Company’s Management determined that it is preferable to change its accounting policy for its oil sands properties and adopt the full cost method under U.S. GAAP to better reflect our non-traditional oil sands resource assets in the Peace River oil sands area in Alberta, Canada.

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 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 2016 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.

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 US 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:

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:

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 elsewhere in this Annual Report entitled “Risk Factors” and “Environmental Laws and Regulations”. 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.

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.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Deep Well Oil & Gas, Inc. and subsidiaries

We have audited the accompanying consolidated balance sheets of Deep Well Oil & Gas, Inc. and its subsidiaries (the “Company”) as of September 30, 2016 and 2015, and the related consolidated statements of operations and comprehensive income (loss), shareholders’ equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Deep Well Oil & Gas, Inc. and its subsidiaries at September 30, 2016 and 2015, and the results of their consolidated operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ Turner, Stone & Company LLP

Dallas, Texas

March 8, 2018

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Balance Sheets

September 30, 2016 and September 30, 2015

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Statements of Operations and Comprehensive Income (Loss)

For the Years Ended September 30, 2016 and 2015

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Statements of Shareholders’ Equity

For the Years Ended September 30, 2016 and 2015

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Consolidated Statements of Cash Flows

For the Years Ended September 30, 2016 and 2015

See accompanying notes to the consolidated financial statements

DEEP WELL OIL & GAS, INC. (AND SUBSIDIARIES)

Notes to the Consolidated Financial Statements

September 30, 2016 and 2015

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.

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.

Change in Accounting Principle

During the fourth quarter of 2015, the Company voluntarily changed its method of accounting for its oil and gas properties from the successful efforts method to the full cost method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the full cost method. The Company believes that the full cost method is preferable as it reflects the results of the Company’s operations and the economics of exploring for and developing its non-traditional long life oil sands assets in the Peace River oil sands area in Alberta, Canada. The Company’s consolidated financial statements have been recast to reflect these differences.

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, 2016 and September 30, 2015, 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 2016 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.

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:

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.

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, 2016 and 2015, asset retirement obligations amount to $452,533 and $426,607, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.

Foreign Currency Translation

The functional currency of the Canadian subsidiaries is the United States dollar. However, the Canadian subsidiaries transact in Canadian dollars. Consequently, monetary assets and liabilities are remeasured into United States dollars at the exchange rate on the balance sheet date and non-monetary items are remeasured at the rate of exchange in effect when the assets are acquired or obligations incurred. Revenues and expenses are remeasured at the average exchange rate prevailing during the period. Foreign currency transaction gains and losses are included in results of operations.

Accounting Method

The Company recognizes income and expenses based on the accrual method of accounting.

Dividend Policy

The Company has not yet adopted a policy regarding payment of dividends.

Financial, Concentration and Credit Risk

The Company’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 2016 fiscal year end the Company has approximately $636,029 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 years ended September 30, 2016 and 2015, the Company has recorded oil sales received from the operator of the Company’s producing properties. The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s joint venture partner who sells 100% of the Company’s oil production to 11 purchasers in the oil and gas industry. The Company does not require collateral and management periodically evaluates the operator’s financial statements and the collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and that the risk of loss is minimal.

Income Taxes

The Company utilizes the liability method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities are determined based on the differences between financial reporting and the tax bases of the assets and liabilities, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. An allowance against deferred tax assets is recorded when it is more likely than not that such tax benefits will not be realized.

Due to the uncertainty regarding the Company’s profitability, a valuation allowance has been recorded against the future tax benefits of its losses and no net benefit has been recorded in the consolidated financial statements.

Revenue Recognition

The Company is in the business of exploring for, developing, producing, and selling crude oil. Crude oil revenue is recognized when the product is taken from the storage tanks on the lease and delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred.

Occasionally the Company may sell specific leases, and the gain or loss associated with these transactions will be shown separately from the profit or loss from the operations or sales of oil products. Such gain or losses will be measured and recognized when all of the following have occurred: (1) there is persuasive evidence of an arrangement to sell; (2) the price of the sale is fixed or determinable; (3) the title to the lease has transferred; and (4) collection is reasonably assured.

Advertising and Market Development

The Company expenses advertising and market development costs as incurred.

Basic and Diluted Net Income (Loss) Per Share

Basic net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were 63,685,221 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.

Environmental Requirements

At the report date, environmental requirements related to the oil properties acquired are unknown and therefore an estimate of any future cost cannot be made.

Share-Based Compensation

The Company accounts for stock options granted to directors, officers, employees and non-employees using the fair value method of accounting. The fair value of stock options for directors, officers, 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. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

Estimates and Assumptions

Management uses estimates and assumptions in preparing financial statements in accordance with generally accepted accounting principles. Those estimates and assumptions affect the reported amounts of the assets and liabilities, the disclosure of contingent assets and liabilities, and the reported revenues and expenses. Actual results could vary from the estimates that were used in preparing these consolidated financial statements.

Significant estimates by management include valuations of oil properties, valuation of accounts receivable, useful lives of long-lived assets, asset retirement obligations, valuation of share-based compensation, and the realizability of future income taxes.

The Company’s oil sands acreage as of September 30, 2016, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:

Lease Rental Commitments

The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The terms include certain commitments related to oil sands properties that require the payments of rents as long as the leases are non-producing. As of September 30, 2016, the Company’s net payments due under this commitment are as follows:

The government of Alberta owns this land and the Company has acquired the rights to perform oil activities on these lands. If the Company meets the conditions of the leases the Company will then be permitted to drill on and produce oil from the land into perpetuity. These conditions give the Company until the expiration of the leases to meet the following requirements on its oil sands leases:

With the revised requirements, the Company now plans to meet the first of these conditions. As at September 30, 2016 and 2015, out of the 26 wells to be drilled in option 1 above, the Company has an interest in ten wells which it has drilled, logged and cored, which can be counted towards these requirements, and in addition the Company has also identified three other wells drilled and logged through the oil sands zone by others who own or owned the rights to explore zones deeper than the Company’s Bluesky zone where the Company has oil sands rights. The wells drilled by others may be included in the satisfaction of these requirements under option 1 above. Therefore, under option 1 above the Company may have to drill up to another 13 wells to preserve all of the 68 sections. In the event the Company does not drill all or part of the 13 wells the Company can also elect to retain a portion of each lease where the Company has identified the reservoir and has completed the amount of work to retain that portion of the lease. Presently, without drilling any more wells it is the Company’s opinion that under the newer rules the Company can retain about 67% of the lands where the Company has already identified resources.

In the event that the Company uses option 2 above, the Company has also acquired and processed 25 miles of seismic on the leases, which can be counted towards the option 2 requirements. The Company’s joint venture partner and operator of the SAGD Project has also acquired additional seismic that can be used towards the requirements under option 2 above.

The Company follows the full cost method of accounting for costs of oil properties. Under this method, oil and gas properties, for which no proved reserves have been assigned, must be assessed at least annually to ascertain whether or not a write down should occur. Unproven properties are assessed annually, or more frequently as economic events indicate, for potential write down.

This consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. Proven oil properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for the year ended September 30, 2016.

Capitalized costs of proven oil properties will be depleted using the unit-of-production method when the property is placed in production.

Substantially all of the Company’s oil activities are conducted jointly with others. The accounts reflect only the Company’s proportionate interest in such activities.

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 SAGD Project at the Company’s Sawn Lake heavy oil reservoir in North Central Alberta, Canada. In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for the Company’s portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where the Company had a working interest of 50% (before the execution of the Farmout Agreement). The Farmee will also provide funding to cover monthly operating expenses of the Company, of which the first such monthly payment began in respect of the month of August 2013 and shall not to exceed $30,000 per month. In addition, until December 31, 2015, as amended on November 17, 2014, the Farmee has the option to elect to obtain a working interest of 45% to 50% working interest in the remaining 56 sections of land where the Company has working interests ranging from 90% to 100%, by committing an additional $110,000,000 of financing to the development of the Company’s Sawn Lake oil sands properties. As of the date of the options expiration, December 31, 2015, the Farmee did not exercise its option to acquire such interests.

The following table illustrates capitalized costs relating to oil producing activities as of September 30, 2016 and September 30, 2015:

Depreciation and depletion expenses for the years ended September 30, 2016 and 2015 were $11,274 and $10,549 respectively.

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, 2016 and September 30, 2015:

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 December 31, 2015, which is Andora’s fiscal year end. These shares are carried at a nominal value using the cost method and their value is included under oil and gas properties on the Company’s balance sheet.

There was $42,115 of depreciation expense for the year ended September 30, 2016 (September 30, 2015 - $55,228).

Long-term investments consist of cash held in trust by the AER which bears interest at a rate of prime minus 0.375% and has no stated date of maturity. These investments are required by the AER to ensure there are sufficient future cash flows to meet the expected future asset retirement obligations and are restricted for this purpose.

Accounts payable – related parties was $2,469 as of September 30, 2016 (September 30, 2015 - $4,833) for expenses to be reimbursed to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.

As of September 30, 2016, officers, directors, their families, and their controlled entities have acquired 53.63% of the Company’s outstanding common capital stock. This percentage does not include unexercised warrants or stock options.

The Company incurred expenses $135,828 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, 2016 (September 30, 2015 - $147,006). These amounts were fully paid as of September 30, 2016.

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At September 30, 2016, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $616,191 (September 30, 2015 - $602,613). The fair value of the liability at September 30, 2016 is estimated to be $452,533 (September 30, 2015 - $426,607) using a risk free rate of 3.74% and an inflation rate of 2%. The actual costs to settle the obligation are expected to occur in approximately 27 years.

Changes to the asset retirement obligation were as follows:

As of September 30, 2016, the Company had outstanding 229,374,605 shares of common stock.

Warrants

On June 23, 2014, 47,618 common share purchase warrants were transferred to a non-related party.

On October 3, 2014, a warrant holder of the Company acquired 47,618 shares of the Company’s common stock, upon exercising warrants, at an exercise price of $0.105 per share of common stock for gross proceeds to the Company of $5,000.

On July 28, 2015, the Company’s Board approved the extension of the expiration date of some warrants to purchase shares of the Company’s common stock. The exercise price of the warrants remained unchanged at $0.105 per share. As a result of this extension, the expiration dates of the warrants were amended from the original expiry date of November 23, 2015 to November 23, 2016, with all other terms of the original warrants remaining in full force and effect. In consideration of extending the expiry date of this series of warrants, the number of outstanding warrants was reduced from 71,857,141 to 52,155,221 common share purchase warrants.

The Company valued the affected warrants immediately before and after the warrants modification. The value of the warrants after the modification was increased by $443,062, resulting in an accounting adjustment to additional paid-in capital and accumulated deficit in the consolidated statements of shareholders’ equity.

On June 20, 2016, warrants to acquire up to 520,000 common shares of the Company, expired unexercised.

The following table summarizes the Company’s warrants outstanding as of September 30, 2016:

The following is a summary of warrant activity for the year ended September 30, 2016:

There were 52,155,221 warrants outstanding as of September 30, 2016 (September 30, 2015 – 52,675,221), which have a fair value of $3,153,216 (September 30, 2015 - $3,153,216).

Measurement Uncertainty for Warrants

The Company used the Black-Scholes pricing model (“Black-Scholes”) to value the warrants. This pricing model was developed for use in estimating the fair value of traded “European” options. The private placement warrants issued by the Company are transferable and have no vesting restrictions and can be exercised at any time up to their expiration date, 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 warrants. The following assumptions were used in the Black-Scholes pricing model to value the warrants:

Expected Term – Expected term of 1.33 years, represents the period that the warrants were 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 was 111%.

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 was 0.67%

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.

Prior to October 1, 2013, the Company had a total of 4,350,000 options outstanding, that were previously granted to directors, consultants and an employee of the Company on March 23, 2011 and June 20, 2013, to purchase up to 3,450,000 and 900,000 shares, respectively, each of common stock at exercise prices ranging from $0.14 to $0.05, respectively, of which a total of 950,000 options granted on June 20, 2013 remain unvested.

On October 28, 2013, the Company granted a contractor an option to purchase 250,000 shares of common stock at an exercise price of $0.30 per Common Share, all vesting immediately, with a five-year life, for his services in connection with the Farmout Agreement dated July 31, 2013.

On December 4, 2013, the Company appointed a new director to its Board and in connection with the appointment the Company granted the new director an option to purchase 450,000 shares each of common stock at an exercise price of $0.34 per Common Share, 150,000 vesting immediately and the remaining vesting one-third on December 4, 2014, and one-third on December 4, 2015, with a five-year life.

On September 19, 2014, the Company granted seven of its directors options to purchase 600,000 shares each of common stock at an exercise price of $0.38 per Common Share, 200,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with a five-year life.

On September 19, 2014, the Company granted two consultants an option to purchase each 1,200,000 shares each of common stock at an exercise price of $0.38 per Common Share, 600,000 vesting immediately and remaining vesting on September 19, 2015.

On September 19, 2014, the Company granted one employee an option to purchase 180,000 shares each of common stock at an exercise price of $0.38 per Common Share, 60,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with a five-year life.

On November 17, 2014, the Company appointed a new director to its Board and in connection with the appointment the Company granted the new director an option to purchase 600,000 shares each of common stock at an exercise price of $0.23 per Common Share, 200,000 vesting immediately and the remaining vesting one-third on November 17, 2015, and one-third on November 17, 2016, with a five-year life.

On March 23, 2016, 900,000 stock options previously granted on March 23, 2011 to two directors, expired unexercised.

For the year ended September 30, 2016, the Company recorded share-based compensation expense related to stock options in the amount of $237,971 (September 30, 2015 – $ 1,116,544) on the stock options that were previously granted. As of September 30, 2016, there was remaining unrecognized compensation cost of $2,314 related to the non-vested portion of these unit option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.

The aggregate intrinsic value of exercisable options as of September 30, 2016, was $Nil (September 30, 2015 - $Nil).

The following is a summary of stock option activity as at September 30, 2016:

A summary of the options granted at September 30, 2016 and 2015 and changes during the periods then ended is presented below:

There were 200,000 unvested stock options outstanding as of September 30, 2016 (September 30, 2015 – 2,010,000).

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%.

As of September 30, 2016, the Company has approximately $6,184,515 (2015 – $6,067,348) of operating losses expiring through 2035 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, 2016, the Company had an unused Canadian net operating loss carry-forward of approximately $7,691,984 (2015 – $8,447,043), expiring through 2036. These operating loss carry-forwards may result in future income tax benefits of approximately $4,241,416. 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:

The approximate tax effects of each type of temporary difference that gives rise to deferred tax assets are as follows:

In accordance with generally accepted accounting principles, the Company has analyzed 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.

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 $11,436 per month (Cdn $15,000 per month). As of September 30, 2016, the Company did not owe Concorde Consulting any of this amount.

Rental Agreement

On July 27, 2015, the Company renewed its Edmonton office lease commencing effective on July 1, 2015 and expiring on June 30, 2017. The quarterly payments due are as follows:

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, 2016 and 2015: