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, ~~2018~~2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ~~______~~ ____ to ______

Commission File Number: 0-24012

DEEP WELL OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada		98-0501168
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Suite 700, 10150 – 100 Street, Edmonton, Alberta, Canada		T5J 0P6
(Address of principal executive offices)		(Zip Code)

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

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

Title of each class Trading Symbol(s) Name of each exchange on which registered None None None

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

Common Stock, $0.001 par value per share

(Title of class)

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ☐

Indicate by check mark whether the registrant has submitted electronically ~~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 þ No ☐

Indicate by check mark ifwhether ~~disclosure~~the ofregistrant ~~delinquent~~is ~~filers~~a ~~pursuant~~large toaccelerated ~~Item~~filer, ~~405~~an ofaccelerated ~~Regulation~~filer, Sa non-Kaccelerated ~~(§229.405~~filer, ofa ~~this~~smaller ~~chapter) is not~~reporting ~~contained herein~~company, ~~and~~or ~~will~~an ~~not~~emerging begrowth ~~contained,~~company. toSee the ~~best~~definitions of ~~registrant’s~~“large ~~knowledge~~accelerated filer,” in“accelerated ~~definitive~~filer,”, “smaller ~~proxy~~reporting orcompany,” ~~information~~and ~~statements incorporated~~“emerging bygrowth ~~reference~~company” in ~~Part~~Rule ~~III~~12b-2 of ~~this~~the ~~Form~~Exchange ~~10-K or any amendment to this Form 10-K~~Act. ☐

~~Indicate by~~Large ~~check mark whether the registrant is a large~~ accelerated filer, an☐ ~~accelerated~~Accelerated filer, a☐ ~~non~~Non-accelerated filer, a☐ ~~smaller~~Smaller reporting ~~company,~~ ~~or emerging growth~~ company. ~~See~~þ ~~the~~Emerging ~~definitions of “large accelerated filer,” “accelerated filer,”, “smaller reporting company,” and “emerging~~ growth company” ~~in Rule 12b-2 of the Exchange Act.~~þ

Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☐ (Do not check if a smaller reporting company) Smaller reporting company þ Emerging growth company þ

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No þ

The aggregate market value of the registrant’s common stock held by non-affiliates computed by reference to the price at which the common equity was sold on or about March 31, ~~2018~~2019 was approximately $2.59 million.

As of ~~December~~January 2113, ~~2018~~2020, the Issuer had outstanding approximately 230,574,603 shares of common stock, $0.001 par value per share.

TABLE OF CONTENTS

TABLE OF CONTENTS
		Page Number

GLOSSARY AND ABBREVIATIONS		ii

CURRENCY EXCHANGE RATES		iv

PART I

ITEM 1.	BUSINESS	1

ITEM 1A.	RISK FACTORS	4

ITEM 2.	PROPERTIES	7

ITEM 3.	LEGAL PROCEEDINGS	9

ITEM 4.	MINE SAFETY DISCLOSURES	10

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	11

ITEM 6.	SELECTED FINANCIAL DATA	12

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	19

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	37

ITEM 9A.	CONTROLS AND PROCEDURES	37

ITEM 9B.	OTHER INFORMATION	37

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	38

ITEM 11.	EXECUTIVE COMPENSATION	42

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	43

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	46

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	46

PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	48

ITEM 16.	FORM 10-K SUMMARY	49

		Page Number
GLOSSARY AND ABBREVIATIONS		ii
CURRENCY EXCHANGE RATES		iii
	PART I
ITEM 1.	BUSINESS	1
ITEM 1A.	RISK FACTORS	5
ITEM 1B	UNRESOLVED STAFF COMMENTS	8
ITEM 2.	PROPERTIES	9
ITEM 3.	LEGAL PROCEEDINGS	13
ITEM 4.	MINE SAFETY DISCLOSURES	13
	PART II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	14
ITEM 6.	SELECTED FINANCIAL DATA	15
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	22
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	F-1
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	23
ITEM 9A.	CONTROLS AND PROCEDURES	23
ITEM 9B.	OTHER INFORMATION	24
	PART III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	25
ITEM 11.	EXECUTIVE COMPENSATION	29
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	32
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	34
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	35
	PART IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	36
ITEM 16.	FORM 10-K SUMMARY	38

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.

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~~Farmout ~~Oil~~ – ~~oil having~~ an ~~API~~arrangement ~~gravity less than 22.3 degrees. Horizontal Well –~~ whereby the ~~drilling~~owner of a ~~well~~lease ~~that~~assigns ~~deviates~~some ~~from~~ownership ~~the~~portion ~~vertical~~(or ~~and~~all) ~~travels horizontally through a producing layer~~ of ~~a reservoir. In-situ – in~~ the ~~oil sands context~~ lease(~~in-situ means “in place” in Latin~~s), ~~in-situ methods such as SAGD or CSS through horizontal or vertical wells maybe required~~ to ~~produce~~another ~~the~~company ~~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~~Farmee”) –in areturn for ~~surface crown agreement issued by~~ the ~~Alberta~~Farmee ~~Department~~paying offor ~~Sustainable Resources Development granting~~ the ~~mineral~~drilling ~~producer~~on 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 22some ~~degrees~~portion ~~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~~s) – 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 estimationFarmout. 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.

Gross Acre/Hectare – a gross acre is an acre in which any portion of a working interest is owned. 1 acre = 0.4046 hectares. 1 hectare = 2.471 acres.

Heavy Oil – oil having an API gravity less than 22.3 degrees.

Horizontal Well – the drilling of a well that deviates from the vertical and travels horizontally through a producing layer of a reservoir.

In-situ – in the oil sands context (in-situ means “in place” in Latin), in-situ methods such as SAGD or CSS through horizontal or vertical wells maybe required to produce the oil if the oil sands deposits are too deep to mine from the surface.

Lease – a legal document giving an operator the right to drill for or produce oil or gas; also, the land on which a lease has been obtained.

License of Occupation (“LOC”) – a surface crown agreement issued by the Alberta Department of Sustainable Resources Development granting the mineral producer the right to occupy public lands for an approved purpose, usually issued primarily for access roads or to construct access roads but may also be issued for other purposes.

Light Crude Oil – liquid petroleum which has a low density and flows freely at room temperature. Also called conventional oil, it has an API gravity of at least 22 degrees and a viscosity less than 100 centipoise.

Mbbl or Mbbls – means one thousand barrels or thousands of barrels.

MMbbl or MMbbls – means one million barrels or millions of barrels.

Mmcf – means million cubic feet.

Mineral Surface Lease (“MSL”) – a surface crown agreement issued by the Alberta Department of Sustainable Resources Development granting the mineral producer the right to construct a well site on publicly owned land.

Net Acre/Hectare – a net acre is the result that is obtained when the fractional ownership working interest of a lease is multiplied by gross acres of that lease.

Oil Sands – naturally occurring mixtures of bitumen, water, sand and clay that are found mainly in three areas of Alberta - Athabasca, Peace River and Cold Lake. A typical sample of oil sand might contain about 12% bitumen by weight.

Pay Zone (Net Oil Pay) – the producing part of a formation.

Permeability – the capacity of a reservoir rock to transmit fluids; or how easily fluids can pass through a rock. The unit of measurement is the darcy or millidarcy.

Porosity – the capacity of a reservoir to store fluids, the volume of the pore space within a reservoir, measured as a percentage.

Possible Reserves * – additional unproved reserves that analysis of geological and engineering data suggests are less likely to be recoverable than probable reserves but have at least a ten percent probability of being recovered.

Primary Recovery – the production of oil and gas from reservoirs using the natural energy available in the reservoirs and pumping techniques.

Proved Developed Reserves * – are those reserves that can be expected to be recovered.

Probable Reserves * – additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

iii

~~Saturation~~Proved –Reserves ~~the~~* ~~relative~~– ~~amount~~estimated quantities of ~~water,~~crude oil, ~~and~~natural gas ~~in the pores of a rock~~, ~~usually~~and asnatural agas ~~percentage~~liquids ofwhich ~~volume.~~geological ~~SEC – means United States Securities~~ and ~~Exchange~~engineering ~~Commission.~~data ~~Section~~demonstrate –with inreasonable certainty ~~reference~~ to abe ~~parcel~~recoverable ofin ~~land,~~future ~~meaning~~years anfrom ~~area~~known ofreservoirs ~~land~~under ~~comprising~~existing ~~approximately~~economic, ~~640~~operating ~~acres.~~methods, ~~Service~~and ~~Well~~government –regulations prior ato ~~well drilled or completed for~~ the ~~purpose~~time ofat ~~supporting~~which ~~production~~contracts inproviding anthe ~~existing~~right ~~field.~~to ~~Specific~~operate ~~purposes of service wells include gas injection~~expire, ~~water~~unless ~~injection,~~evidence ~~steam~~indicates ~~injection,~~that ~~air~~renewal ~~injection,~~is ~~salt-water disposal~~reasonably certain, ~~water~~regardless ~~supply~~of ~~for~~whether ~~injection,~~deterministic ~~observation,~~ or ~~injection~~probabilistic ~~for~~methods ~~in-situ~~are ~~combustion.~~used ~~Solution~~for ~~Gas~~the ~~– natural gas that is found “in solution” within crude oil in underground reservoirs~~estimation. ~~When~~The ~~the~~project ~~oil comes~~ to ~~the~~extract ~~surface,~~ the ~~gas~~hydrocarbons must ~~expands~~have ~~and~~commenced ~~comes~~or ~~out~~the ofoperator ~~the~~must ~~solution.~~be ~~Specific~~reasonably ~~Gravity~~certain –that ~~the~~it ~~ratio~~will ofcommence the ~~heaviness~~project ofwithin a ~~substance~~reasonable ~~compared to that of the same volume of water~~time.

~~Steam-Assisted~~Proved ~~Gravity~~Undeveloped ~~Drainage~~Reserves ~~(“SAGD”)~~* – are ~~pairs~~those ofreserves ~~horizontal~~that ~~wells (an upper well and a lower well)~~ are ~~drilled~~expected ~~into~~to anbe ~~oil~~recovered ~~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~~new 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~~on ~~pay~~undrilled 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$acreage, ~~USD,~~ or USfrom ~~dollar~~existing -wells ~~means~~where ~~United States dollars. Viscosity –~~ a ~~measure~~relatively major ofexpenditure 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~~required ~~it to flow. Centipoise is the common unit~~ for ~~expressing absolute viscosity~~recompletion. ~~Viscosity matters to producers because the oil’s viscosity at reservoir temperature determines how easily oil flows to the well for extraction.~~

Saturation – the relative amount of water, oil, and gas in the pores of a rock, usually as a percentage of volume.

SEC – means United States Securities and Exchange Commission.

Section – in reference to a parcel of land, meaning an area of land comprising approximately 640 acres.

Service Well – a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Solution Gas – natural gas that is found “in solution” within crude oil in underground reservoirs. When the oil comes to the surface, the gas expands and comes out of the solution.

Specific Gravity – the ratio of the heaviness of a substance compared to that of the same volume of water.

Steam-Assisted Gravity Drainage (“SAGD”) – pairs of horizontal wells (an upper well and a lower well) are drilled into an oil sands formation and steam is injected continuously into the upper well. As the steam heats the oil sands formation, the bitumen softens and drains into the lower well, from which it is brought to the surface.

Steam to Oil Ratio (“SOR”) – measures the number of barrels of steam (measured in “Cold Water Equivalent Barrels”) needed for every barrel of oil produced.

Thermal Recovery – a type of improved recovery in which heat is introduced into a reservoir to lower the viscosity of heavy oils and to facilitate their flow into producing wells. The pay zone may be heated by injecting steam (steam drive) or by injecting air and burning a portion of the oil in place (in situ combustion).

Upgrading – the process that converts bitumen and heavy oil into a product with a density and viscosity similar to conventional light crude oil.

US$, USD, or US dollar - means United States dollars.

Viscosity – a measure of a fluid’s resistance to flow. To simplify, the oil’s viscosity represents the measure for which the oil wants to stay put when pushed by moving mechanical components. It varies greatly with temperature. The more viscous the oil the greater the resistance and the less easy it is for it to flow. Centipoise is the common unit for expressing absolute viscosity. Viscosity matters to producers because the oil’s viscosity at reservoir temperature determines how easily oil flows to the well for extraction.

* This definition is an abbreviated version of the complete definition as defined by the SEC under Rule 4-10(a) of Regulation S-X.

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, as reported by the Bank of Canada.

Year ending September 30	~~2018~~2019		~~2017~~2018
Rate at year end	$	0.~~7725~~7551	$	0.~~8013~~7725
Average rate for year	$	0.~~7793~~7537	$	0.~~7610~~7793

Unless the context indicates another meaning, the terms “Company,” “Deep Well,” “we,” “us” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries through which it conducts business. For definitions of some terms used throughout this report, see “Glossary and Abbreviations”.

PART I

ITEM 1.

BUSINESS

We are an independent junior oil sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base in the Peace River oil sands area of Alberta. Our principal office is located at Suite 700, 10150 – 100 Street NW, Edmonton, Alberta T5J 0P6, our telephone number is (780) 409-8144 and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and our common stock trades on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com ~~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, ~~2018~~2019 (this “Annual Report”).

Formation of Organization

Deep Well Oil & Gas, Inc. was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. and in connection with a plan of reorganization, effective on September 10, 2003, the Company was reorganized and changed its name to Deep Well Oil & Gas, Inc. Deep Well Oil & Gas, Inc. has two wholly owned subsidiaries through which it conducts its operations: (1) Northern Alberta Oil Ltd. (“Northern”) acquired on June 7, 2005, and incorporated under the Business Corporations Act (Alberta), Canada on September 18, 2003; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005.

Deep Well Oil & Gas, Inc. has two wholly owned subsidiaries through which it conducts its operations: (1) Northern Alberta Oil Ltd. (“Northern”) acquired on June 7, 2005, and incorporated under the Business Corporations Act (Alberta), Canada on September 18, 2003; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005.

Business Development

~~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, (also known as our Sawn Lake oil sands properties) using thermal recovery technologies. Currently, we have received approval from the Alberta Energy Regulator (“AER”) for two thermal recovery projects located on our Sawn Lake properties.

OnOver ~~July~~the ~~30,~~last ~~2013,~~3 years we ~~entered~~have ~~into~~successfully aapplied ~~Steam~~to ~~Assisted~~the ~~Gravity~~AER ~~Drainage~~to ~~Demonstration~~continue ~~Project~~the ~~Joint~~best ~~Operating~~sections ~~Agreement~~of ~~(the~~our ~~“SAGD~~oil sands properties past their ~~Project”)~~initial toexpiry ~~jointly~~dates, ~~participate~~where inresources ~~the~~were ~~Alberta~~identified. ~~Energy~~Under ~~Regulator~~the ~~(“AER”)~~oil ~~approved~~sands ~~SAGD~~lease ~~Project~~continuation onregulations aan ~~portion~~operator or leaseholder ofmust ~~one~~demonstrate ~~section~~certain levels of ~~land~~exploration ~~where~~and wedevelopment ~~have~~by aproviding ~~25%~~the ~~working~~AER ~~interest~~with ~~(post~~drilling, ~~Farmout~~coring ~~Agreement~~and asseismic ~~defined~~data ~~below).~~within a ~~The~~certain ~~SAGD~~timeframe ~~Project~~in isorder ~~located in~~to ~~section~~maintain ~~30-91-12W5~~the oflease ~~our~~past ~~Peace~~its ~~River~~expiry date. For more information regarding our oil sands properties see ~~located~~“Oil inand ~~North~~Gas ~~Central~~Properties” ~~Alberta,~~under ~~Canada~~Item ~~(also~~2 ~~known~~“Properties” asof ~~our~~this ~~Sawn Lake~~Annual ~~oil~~Report ~~sands~~on ~~properties)~~Form 10-K.

OnIn late July ~~31,~~of 2013, we entered into a ~~farmout~~Steam Assisted Gravity Drainage Demonstration Project Joint Operating Agreement (the “SAGD Project”) where we have a 25% working interest with one joint venture partner. In late July of 2013 we entered into a farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”). toThe ~~fund~~SAGD Project ~~our~~produced ~~portion~~bitumen offor 18 months, demonstrating the ~~costs~~productive capability of our Sawn Lake reservoir. In 2016 a majority of our Company’s Joint Venture partners voted to temporarily suspend operations for the SAGD Project. In ~~accordance~~early ~~with~~May of 2016, an amended application was submitted to the ~~Farmout~~AER ~~Agreement~~for an expansion of the ~~Farmee~~ ~~has~~existing ~~agreed~~SAGD toProject ~~provide~~facility site which would potentially increase the operations up to ~~$40,000,000~~a intotal ~~funding~~of ~~for~~eight ~~our~~SAGD ~~portion~~well ofpairs. ~~the~~The ~~costs~~amended ~~for~~application sought approval to expand the current SAGD Project asfacility ~~set~~site ~~out~~to in3,200 ~~the Farmout~~bopd ~~Agreement~~(100% basis). Regulatory approval was received in ~~return~~December 2017 for a ~~net~~commercial ~~25%~~expansion of ~~working~~the ~~interest~~existing inSAGD 12Project ~~sections~~facility site where we ~~had~~have a 25% working interest. ofIt ~~50%~~is ~~before~~anticipated ~~the~~that ~~execution~~only five SAGD well pairs ofwill ~~the~~be ~~Farmout~~needed ~~Agreement.~~to ~~The~~achieve ~~Farmee~~the is3,200 ~~also~~bopd ~~required~~production tolevel. ~~provide~~For ~~funding~~more toinformation ~~cover~~regarding ~~monthly~~our ~~operating~~SAGD ~~expenses~~Project ofand our ~~Company~~Farmout ~~provided~~Agreement, ~~that~~see ~~such~~“Present ~~funding~~Activities ~~shall~~- ~~not~~Peace ~~exceed~~River ~~$30~~Oil Sands,~~000~~ ~~per~~Alberta ~~month~~Canada (Sawn Lake Properties)” under Item 2 “Properties” of this Annual Report on Form 10-K.

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.1

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~~interests in ~~six~~seven oil sands leases ~~and~~ranging afrom ~~100~~25% ~~working~~to ~~interest~~100% in ~~one oil sands lease in~~ the Peace River oil sands area of Alberta, where we are the operator. ~~In addition, we have a 25% working interest, since execution~~ of ~~the~~five ~~Farmout Agreement, in another two oil sands~~ leases ~~in the Peace River oil sands area of Alberta~~. ~~These nine oil sands leases are contiguous and cover 37,322 gross acres (15,104 gross hectares) of which our Company has 29,383 net acres (11,891 net hectares).~~ The focus of our Company’s operations is to ~~exploit~~develop the oil sands reservoir to establish proven reserves and to determine the best technology under which the oil can be produced from our Sawn Lake properties in order to generate positive cash flow. For further information on our oil sands projects see Item 2 “Oil and Gas Properties” in this Annual Report on Form 10-K.

Market and Distribution of Product

On lands where we have a 25% working interest, the operator of the SAGD Project markets and distributes all oil produced from the SAGD Project facility. Production from the SAGD Project was trucked and sold to marketing facilities in the Peace River area of Alberta. A majority of the Joint Venture partners voted to temporarily suspend operations for the SAGD Project at the end of February 2016.

On lands where we are the operator, we intend to sell our oil production under both short-term (less than one year) and long-term (one year or more) agreements at prices negotiated with third parties. Under both short-term and long-term contracts, typically either the entire contract (in the case of short-term contracts) or the price provisions of the contract (in the case of long-term contracts) are renegotiated in intervals ranging in frequency from daily to annual. At this time, we have no production on any of the lands where we are the operator and therefore, we have no short-term or long-term contracts. We will adopt specific sales and marketing plans once production is achieved on lands where we are designated as the operator. The operator of our joint SAGD Project marketed and distributed all oil produced from our joint SAGD Project.

Market pricing for bitumen is seasonal, with lower prices in and around the calendar year-end being the norm due to lower demand for asphalt and other bitumen-derived products. By necessity, bitumen is regularly blended with diluent in order to facilitate its transportation through pipelines to North American markets. As such, the effective field price for bitumen is also directly impacted by the input cost of the diluent required, the demand and price of which is also seasonal in nature (higher in winter as colder temperatures necessitate more diluent for transportation). Consequently, bitumen pricing is usually weakest in and around December and not reflective of the annual average realized price or the economics of the “business” overall. We have been advised that, to price bitumen, marketers apply formulas that take as a reference point the prices published for crude oil of particular qualities such as “Western Canadian Select”, “Brent Crude Oil”, “Crude Bitumen 9 API Plant Gate”, “Edmonton Light”, “Lloydminster Blend”, or the more internationally known “West Texas Intermediate” (“WTI”).

Competitive Business Conditions

We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural gas properties as well as for the equipment, labour and materials required to develop and operate those properties. Many of our competitors have longer operating histories and substantially greater financial and other resources. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage, whereas we may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Larger competitors may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices of gas and oil more easily. Our competitors may also be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.

Competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of Canada and other countries as well as other factors beyond our control, including international political stability, overall levels of supply and demand for oil and gas, and the markets for synthetic fuels and alternative energy sources.

Customers

The operator of our SAGD Project, distributed and sold all of the oil that was produced from the SAGD Project. Production was sold to 11 different marketing facilities in Alberta.

Royalty Agreements

Through the acquisition of Northern, we potentially became a party to the following:

On December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a purported royalty agreement with Mikwec Energy Canada, Ltd. (now known as Northern) that potentially encumbers six of our oil sands leases located within our Sawn Lake properties (the “Purported 6.5% Royalty”). Nearshore claimed ato have received the Purported 6.5% Royalty from Northern on the leased substances on the land interests which Northern holds in the above six oil sands leases. Nearshore was a private corporation incorporated in Alberta, Canada, and was owned and controlled by Mr. Steven P. Gawne and his wife, Mrs. Rebekah J. Gawne, who each owned 50% of Nearshore. Mr. Steven P. Gawne was the President, Chief Executive Officer and a director of Deep Well from February 6, 2004 to June 29, 2005. Nearshore has subsequently transferred part or all of ~~this~~the Purported 6.5% Royalty to other parties. Although we continue to deny the validity of the Purported 6.5% Royalty, we determined that it was in the best interests of our shareholders to come to an arrangement to acquire most of the Purported 6.5% Royalty to prevent a potential encumbrance over our land and the possibility of future litigation resulting from these alleged royalty claims. In our fiscal year 2014, we acquired 5.5% of ~~this~~ the Purported 6.5 % Royalty for a cost of $3.4 million. See Item 3 Legal Proceedings in this annual report on Form 10-K.

Government Approval and Crown Royalties

Exploration and Production. Our operations are subject to Canadian federal and provincial governmental regulations. Such regulations include: requiring approval and licenses for the drilling of wells, regulating the location of wells and the method and ability to produce the wells, surface usage and the restoration of land upon which wells have been drilled, the plugging and abandoning of wells and the transportation of production from our wells. Our operations are also subject to various conservation regulations, including the regulation of in-situ recovery processes, the size of spacing units, the number of wells which may be drilled in a unit, the unitization or pooling of oil and gas properties, the rate of production allowable from oil and gas wells and the ability to produce oil and gas.

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 is referred to as the “energy proportionality clause”.

The Canada – United Sates - Mexico Agreement. Canada, the United States and Mexico have completed negotiations for a new Canada – United States - Mexico Agreement (“CUSMA”). Highlights of the CUSMA include the removal of the provision known as the “energy proportionality clause”; as this clause has never been invoked. The agreement has amended the rule of origin for non-originating diluent to allow up to 40% diluent to move crude oil through pipelines. This change will remove approximately $60 million Cdn per year in duties for Canadian businesses. The CUSMA also has measures that govern the access to or use of energy infrastructure that must be neither unduly discriminatory nor unduly preferential.

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~~Crown ~~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. 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.

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, 2018 and 2017.

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. InLegislation ~~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.3

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, 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.

ITEM 1A.

RISK FACTORS

An investment in our common stock is speculative and involves a high degree of risk and uncertainty. You should carefully consider the risks described below, together with the other information contained in our reports filed with the U.S. Securities and Exchange Commission (“SEC”), including the consolidated financial statements and notes thereto of our Company before deciding to invest in our common stock. The risks described below are not the only ones facing our Company. Additional risks not presently known to us, or that we presently consider immaterial may also adversely affect our Company. If any of the following risks occur, our business, financial condition and results of operations and the value of our common stock could be materially and adversely affected.

Any Development Of Our Resources Will Be Subject To ~~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~~ and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon ~~prescribed~~ prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum ~~product~~ product produced. Penalties and interest may be charged to us if we fail to remit royalties on our production to the Crown as prescribed in the regulation. In addition, there is a risk that the remaining 1% of the Purported 6.5% Royalty could be found to be valid.

We Have A History Of Losses And May Not Achieve Or Sustain Profitability In The Future. Since our inception, we have suffered recurring losses from operations and have been dependent on new investment to sustain our operations. During the years ended September 30, ~~2018~~2019 and ~~2017~~2018 we reported net losses of $~~330~~197,~~131~~135 and $~~293~~330,~~098~~131 respectively. We may not achieve profitability in the foreseeable future, if at all. In addition, our operating expenses may be more than our future revenue growth. We expect our future cost of revenue and operating expenses to continue to increase in the foreseeable future as we continue to expand on our thermal recovery operations at Sawn Lake, Alberta.

Future Price Declines May Result In A Write-Down Of Asset Carrying Values. Effective July 1, 2015, our Company adopted the full-cost method of accounting for costs related to our oil sands properties. Under the full cost method, oil and gas properties are subject to a ceiling test performed quarterly. A ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre ceiling”. The cost centre ceiling is the sum of: (i) present value of the estimated future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor; (ii) the costs of unproved properties not being amortized; (iii) the lower of cost or fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. During the ~~2018~~2019 and ~~2017~~2018 fiscal year, no ceiling test write-downs were recorded for our oil and gas properties. Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired are included in the costs subject to depletion within the full cost pool. A significant decline in oil prices from current levels, or other factors, without other mitigating circumstances, could cause a future write-down of our capitalized costs and a non-cash charge on our income statement.

The Successful Implementation Of Our Business Plan Is Subject To Risks Inherent In The Oil Sands Business. Our oil sands operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties, ~~and~~ to drill exploratory wells and to produce bitumen using thermal recovery technologies. In addition, the cost and timing of drilling, completing, operating and acquiring regulatory approval for thermal recovery operations on our wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If our efforts are unsuccessful in establishing proven reserves, the amounts capitalized as unproven costs may be written down and charged against earnings. Our exploitation and development of oil sands reserves depends upon access to the areas where our operations are to be conducted. We conduct a portion of our operations in regions where we are only able to do so on a seasonal basis. Unless the surface is sufficiently frozen, we are unable to access our properties, drill or otherwise conduct our operations as planned. In addition, if the surface thaws earlier than expected, we must cease our operations for the season earlier than planned. Our operations are affected by road bans imposed from time to time during the break-up and thaw period in the spring. Road bans are also imposed due to ~~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. We have acquired nine oil sands leases in North Central Alberta, Canada. These leases to which we are a party are for a fixed term of 15 years but contain a provision that allows us to extend the term of the lease so long as we meet the minimum level of evaluation as set out by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta. The lease terms include certain commitments related to oil sands properties that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta continued oil sands leases past their expiry dates are subject to escalating rental payments in respect of each term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease. Escalating rent is payable at the end of each term year, while annual rent for leases are due at the beginning of each term year. Lessees of continued oil sands leases may reduce or eliminate their escalating rent obligations by conducting exploration or development work, or research, on the non-producing lease. 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. 32 sections of land under five of our nine oil sands leases were set to expire on July 10, 2018. 17 out of 32 sections contain a majority of the resources identified to date on these five oil sands leases. We have or through of joint venture partner, applied to continue beyond expiry these five leases or parts of these leases where the majority of the oil sands resources have been confirmed. Currently, 20 out of the 32 sections have been granted continuance under the Alberta governmental tenure guidelines. We are currently waiting on approval of another 3 sections of land. As of September 30, 2018, out of the 32 sections on these five leases 9 sections reverted back to the province. 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.4

WeOur ~~Expect~~Interests ~~Our~~Are ~~Operating~~Held ~~Expenses To Increase Substantially~~ In The ~~Future~~Form ~~And~~Of Leases That We May ~~Need~~Be Unable To ~~Raise Additional Funds~~Retain. We have working interests in seven oil sands leases in North Central Alberta, Canada. These leases to which we are a ~~history~~party are for a fixed term of ~~net~~15 ~~losses~~years ~~and~~but ~~expect~~contain a provision that ~~our~~allows ~~operating~~us ~~expenses~~to ~~will~~extend ~~increase~~the ~~substantially~~term ~~over~~of the ~~next~~lease 12so ~~months~~long as we ~~continue~~meet the minimum level of evaluation as set out by the Oil Sands toTenure ~~develop~~Regulation ~~our~~of the Mines and Minerals Act of Alberta. Six of these oil sands leases were successfully continued past their initial 15-year fixed term and are now continued into perpetuity. InThe ~~addition,~~lease weterms ~~may~~include ~~experience~~certain acommitments ~~material~~related ~~decrease~~to inoil ~~liquidity~~sands properties ~~due~~that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta continued oil sands leases past their initial expiry dates are subject to ~~unforeseen~~escalating ~~cash~~rental ~~calls~~payments in respect orof ~~other~~each ~~events~~term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs and ~~uncertainties.~~development Ascosts that are incurred in the term year of a ~~result~~continued lease. Also, wecontinued ~~may~~oil ~~need~~sands toleases ~~raise~~must ~~additional~~pay ~~funds~~escalating rent which is payable at the end of each term year, ~~and~~while ~~such~~annual ~~funds~~rent for continued oil sands leases are due at the beginning of each term year. Lessees of continued oil sands leases may ~~not~~reduce beor ~~available~~eliminate ontheir escalating rent obligations by conducting ~~favourable~~exploration ~~terms~~or development work, ifor atresearch, ~~all~~on the non-producing lease. If we ~~cannot~~fail ~~raise~~to ~~funds~~meet onthe ~~acceptable~~specific ~~terms~~requirements of the lease regarding delay or non-payment of yearly rental payments or yearly escalating rents, wesome ~~may~~or ~~not~~all of our leases may be ~~able~~terminated for failure to ~~execute~~pay ~~our~~the ~~business~~required ~~plan~~yearly rents. We have one oil sands lease that has not yet been continued past its initial expiry date of April 9, ~~take~~2024. It is our opinion that we have met the minimum level of evaluation as set out by governmental requirements ~~advantage~~to continue this lease beyond its 15-year expiry date. There can be no assurance that any of ~~future~~the ~~opportunities~~obligations required to maintain each lease will be met. The termination or ~~respond~~expiration toof ~~competitive~~our ~~pressures~~oil sands leases or ~~unanticipated~~the ~~requirements.~~working ~~This~~interests relating to our leases may reduce our opportunity to exploit a given prospect for production and thus could have a material adverse effect on our business, results of operations and financial condition.

~~Our~~We ~~Ability~~Expect ~~To Produce Sufficient Quantities Of Oil From~~ Our ~~Properties~~Operating ~~May~~Expenses BeTo ~~Adversely~~Increase ~~Affected~~Substantially ByIn ~~A Number Of Factors Outside Of Our Control.~~ The ~~business~~Future ofAnd ~~exploring~~We ~~for~~May ~~and~~Need ~~producing~~To ~~oil~~Raise ~~and~~Additional ~~gas~~Funds. ~~involves~~We have a ~~substantial~~history ~~risk~~ of ~~investment~~net ~~loss.~~losses ~~Drilling oil~~and ~~wells~~expect ~~involves the risk~~ that ~~the~~our ~~wells~~operating ~~may~~expenses bewill ~~unproductive~~increase orsubstantially ~~that,~~over ~~although productive,~~ the ~~wells~~next ~~may~~12 ~~not~~months ~~produce~~as ~~oil~~we incontinue ~~economic~~to ~~quantities.~~move ~~Other~~forward ~~hazards~~to ~~such~~develop asour ~~unusual~~oil orsands ~~unexpected~~leases. ~~geological~~In ~~formations~~addition, ~~pressures,~~we ~~fires, blowouts, loss of circulation of drilling fluids or other conditions~~ may ~~substantially~~experience ~~delay~~a ormaterial ~~prevent~~decrease ~~completion~~in ofliquidity ~~any well. Adverse weather conditions can also hinder drilling operations. A productive well could become uneconomic~~ due to, ~~for example, pressure depletion, water encroachment~~unforeseen orcash ~~mechanical~~calls ~~difficulties, which could impair~~ or ~~prevent~~other ~~the~~events ~~production~~and ~~from the well~~uncertainties. ~~There~~As ~~can~~a beresult, ~~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~~need ~~by numerous factors beyond our control. The marketability of our production will depend on the proximity of our reserves~~ to ~~and~~raise ~~the~~additional ~~capacity of~~funds, ~~third party facilities~~ and ~~services,~~such ~~including~~funds ~~oil~~may ~~and~~not ~~natural~~be ~~gas gathering systems, pipelines, trucking~~available oron ~~terminal~~favourable ~~facilities~~terms, ~~and~~if ~~processing~~at ~~facilities~~all. ~~The~~If ~~unavailability~~we orcannot ~~insufficient~~raise ~~capacity~~funds ofon ~~these~~acceptable ~~facilities and services could force us to shut-in producing wells~~terms, ~~delay~~we ~~the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance. There~~ may not be ~~periods~~able ~~of time when pipeline capacity is inadequate~~ to ~~meet~~execute our ~~oil~~business ~~transportation needs. During periods when pipeline capacity is inadequate~~plan, take weadvantage ~~may~~of befuture ~~forced to~~opportunities ~~reduce production~~ or ~~incur~~respond ~~additional expense as existing production is compressed~~ to ~~fit~~competitive ~~into~~pressures ~~existing~~or ~~pipelines.~~unanticipated ~~Other risk factors include availability of drilling and related equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection~~requirements. ~~Our~~This ~~ability to manage these factors~~ could have a material adverse effect on our business, results of operations and financial condition.

6Our Ability To Produce Sufficient Quantities Of Oil From Our Properties May Be Adversely Affected By A Number Of Factors Outside Of Our Control. The business of exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil sands wells involves the risk that the wells may be unproductive or that, although productive, the wells may not produce oil in economic quantities. Other hazards such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well could become uneconomic due to, for example, pressure depletion, water encroachment or mechanical difficulties, which could impair or prevent the production from the well. There can be no assurance that oil will be produced from all of our properties in which we have interests. Marketability of any oil that we acquire or discover may be influenced by numerous factors beyond our control. The marketability of our production will depend on the proximity of our reserves to and the capacity of, third party facilities and services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities. The unavailability or insufficient capacity of these facilities and services could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance. There may be periods of time when pipeline capacity is inadequate to meet our oil transportation needs. During periods when pipeline capacity is inadequate, we may be forced to reduce production or incur additional expense as existing production is compressed to fit into existing pipelines. Other risk factors include availability of drilling and related equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. Our ability to manage these factors could have a material adverse effect on our business, results of operations and financial condition.

We Do Not Control All Of Our Operations. We do not operate all of our oil sands properties and we therefore have limited influence over the testing, drilling and production operations of those properties. Currently, we have a 90% working interest on ~~six~~four oil sands leases, a 100% working interest on one oil sands lease, where we are the operator of the 90% and 100% leases. We also have a 25% working interest on two oil sands leases where one of our joint venture partners is the operator. All ~~nine~~seven oil sands leases are located in the Peace River oil sands area of Alberta, Canada. Our lack of operational control of the two leases currently not operated by us means we are exposed to the following possibilities:

●

the operator might initiate exploration or development on a faster or slower pace than we prefer, or shut-in a currently existing project;

●

the operator might propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which could mean that we are unable or decline to participate in the project or share in the revenues generated by the project;

●

if the operator does not initiate a joint operation proposal to conduct further operations on these two leases, the non-operators are entitled to propose a joint operation that is separate from any already existing project. As a non-operator on those two leases, we might be unable to pursue further operations on the two leases unless we and possibly other joint participating non-operators directly pay the entire cost thereof.

Any of these events could materially reduce the value of those properties affected.

Aboriginal Peoples May Make Claims Regarding The Lands On Which Our Operations Are Conducted. ~~Aboriginal~~The ~~peoples~~AER ~~have~~governs ~~claimed~~our ~~aboriginal~~operations in Alberta, ~~title~~Canada and ~~rights~~they tohave implemented a ~~substantial~~directive ~~portion~~(“Directive 056”) through which the government of ~~western~~Alberta ~~Canada.~~has ~~Since~~issued its ~~aboriginal~~First ~~peoples~~Nations ~~have~~Consultation ~~filed~~Policy aon ~~claim~~Land ~~claiming~~Management ~~aboriginal~~and ~~title~~Resource Development on May 16, 2005. The AER expects that all industry orapplicants ~~rights~~adhere to this policy and the ~~lands~~consultation onguidelines. ~~which~~These ~~some~~requirements and expectations apply to the licensing of all new energy developments and all modifications to existing energy developments, as covered in Directive 056. In the policy, the government of Alberta has developed consultation guidelines to address specific questions about how consultation for land management and resource development should occur in relation to specific activities. Prior to filing an application, we must address all questions, objections, and concerns regarding our ~~properties~~proposed ~~are~~development ~~located~~projects and attempt to resolve them. This includes concerns and objections raised by members of the public, industry, government representatives, First Nations, Métis, and other ifinterested ~~such~~parties. This process can cause significant delays in obtaining a ~~claim~~drilling ispermit ~~successful,~~for itexploration and/or a production well license for both oil and gas and 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. political and economic environment, weather conditions, the availability and market acceptance of alternate fuel sources, transportation interruption, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that could limit future drilling activities for the industry. Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil pricing not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in oil prices could result in non-cash charges to earnings due to write-downs. Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation of projects. We expect that commodity prices will continue to fluctuate significantly in the future.

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. Although we are presently up to date in our current filings, in the past we have not timely filed all of our annual and quarterly reports required to be filed by us with the SEC, in a timely manner. It is possible that the SEC could take enforcement action against us, including potentially the de-registration of our securities, if we fail to file our annual and quarterly reports in a timely manner as required by the SEC. If the SEC were to take any such actions, it could adversely affect the liquidity of trading in our common stock and the amount of information about our Company that is publicly available.

Broker-Dealers Are Not Permitted To Solicit Trades In Our Common Stock. Our common stock is considered to be a “penny stock” because it meets one or more of the definitions of “penny stock” in Rule 3a51-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The principal result or effect of being designated a “penny stock” is that securities broker-dealers cannot recommend the stock and may only trade in it on an unsolicited basis. The continued inability of brokers to recommend our stock could have a material adverse effect on our business, results of operations and financial condition.

Risks Related To Broker-Dealer Requirements Involving Penny Stocks / Risks Affecting Trading and Liquidity. Section 15(g) of the Exchange Act and Rule 15g-2 promulgated thereunder by the SEC require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor’s account. These rules may have the effect of reducing the level of trading activity in the secondary market, if and when one develops. Potential investors in our common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be “penny stock.” Moreover, SEC Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor’s financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in our stock to resell their shares to third parties or to alternatively dispose of them in the market or otherwise.

Potential investors in our common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be “penny stock.” Moreover, SEC Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor’s financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in our stock to resell their shares to third parties or to alternatively dispose of them in the market or otherwise.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

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 ~~six~~four oil sands leases, a 100% working interest in one oil sands lease, and a 25% working interest in an additional two oil sands leases in the Peace River oil sands area of Alberta. These ~~nine~~seven oil sands leases ~~are contiguous and~~ cover 3719,~~322~~ 610 gross acres (157,~~104~~936 gross hectares) with our Company having 2913,~~383~~442 net acres (115,~~891~~440 net hectares). We are the operator of ~~seven~~ five of these oil sands leases where we have working interests of either 90% or 100%. For further information, see Oil and Gas Properties on our Balance Sheet and Note 3, 4 and 5 in the notes to our consolidated financial statements contained herein.

The following table ~~summarize~~summarizes, by geographic area, our gross and net developed and undeveloped ~~Peace~~acreage ~~River oil sands rights under lease~~ as of September 30, ~~2018~~2019:

Peace River Oil Sands Rights as of September 30, 2018
	Gross Hectares		Net Hectares		Gross Acres		Net Acres
Developed Acreage
Alberta, Canada		0		0		0		0
Total		0		0		0		0
Undeveloped Acreage
Alberta, Canada		15,104		11,891		37,322		29,383
Total		15,104		11,891		37,322		29,383
TOTAL Developed and Undeveloped		15,104		11,891		37,322		29,383

sawn lake properties - Peace River Oil Sands as of September 30, 2019

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.

	Gross Hectares		Net Hectares		Gross Acres		Net Acres
Developed Acreage
Alberta, Canada		0		0		0		0
Total		0		0		0		0

Undeveloped Acreage
Alberta, Canada		7,936		5,440		19,610		13,442
Total		7,936		5,440		19,610		13,442

TOTAL Developed and Undeveloped		7,936		5,440		19,610		13,442

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 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. Continued leases are subject to escalating yearly rents provided that they are non-producing and may be offset by any eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease. 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.7

Our ~~developed~~Sawn ~~and~~Lake ~~undeveloped~~ oil sands ~~acreage~~properties under lease as of September 30, ~~2018~~2019, covers 3719,~~322~~610 gross acres (2913,~~383~~442 net acres) of land under ~~nine~~seven oil sands leases. ~~Until~~The ~~we extend the leases “into perpetuity” based on the Alberta governmental regulations, the~~ lease expiration dates of our ~~nine~~Company’s oil sands leases are as follows:

(i) 32Out ~~sections~~ of ~~land~~20,242 gross acres (13,284 net acres) under five oil sands leases were set to ~~expire~~expiry on July 10, 2018., 1714,549 ~~out~~gross ofacres 32(8,571 ~~sections~~net ~~contain~~acres) awere ~~majority~~granted ofcontinuation under the ~~resources~~Alberta ~~identified~~Oil toSands Tenure regulations and have no set expiry date. onIn November of 2017, our Company’s joint venture partner and operator of two of these five oil sands leases., Wesubmitted ~~have~~two orcontinuation ~~through~~applications ofto ~~joint~~the ~~venture~~Alberta ~~partner~~Oil Sands Tenure division to apply to continue 7,591 ~~have~~gross ~~applied~~acres (1,898 net acres) and in January 2018, approval was received from Alberta Energy to continue ~~beyond~~6,958 ~~expiry~~gross ~~these~~acres ~~five~~(1,740 ~~leases~~net oracres). ~~parts~~In June 2018, our Company as operator of three of these five oil sands leases, ~~where~~submitted ~~the~~three ~~majority~~continuation ofapplications to the ~~oil~~Alberta ~~sands~~Oil ~~resources~~Sands ~~have~~Tenure ~~been~~division ~~confirmed.~~to ~~Currently~~apply to continue another 7,591 20gross ~~out~~acres of(6,832 ~~the~~net 32acres) ~~sections~~where ~~have~~resources ~~been~~were ~~granted~~identified ~~continuance~~and ~~under~~in ~~the~~July 2018 and April 2019, approval was received from Alberta ~~governmental~~Energy ~~tenure~~to ~~guidelines~~continue 7,591 gross acres (6,832 net acres). WeOf ~~are~~these ~~currently~~five ~~waiting~~oil sands leases that were set to expiry on ~~approval~~July of10, ~~another~~2018, 3a ~~sections~~total of ~~land~~5,693 gross acres (4,713 net acres) expired without being continued. AsThese ofexpired ~~September~~lands ~~30,~~were ~~2018~~primarily areas where our Company determined that there was no or limited exploitable resources. These continued leases are now held by our Company for perpetuity, ~~out~~subject ofto ~~the~~yearly 32escalating ~~sections~~rental 9payments ~~sections~~until ~~reverted~~they ~~back~~are deemed to ~~the~~be ~~province.~~producing leases;

(ii) 3119,610 ~~sections~~gross ofacres ~~land~~(17,649 net acres) under the three most northern oil sands leases ~~are~~were set to expire on August 19, 2019. In August 2019, our Company submitted one continuation application to the Alberta Oil Sands Tenure division to apply to continue 1,898 acres (1,708 net acres) of the 19,610 gross acres (17,649 net acres) on one of the northern most leases and subsequently in early October 2019 approval was received from Alberta Energy to continue 1,898 gross acres (1,708 net acres) past the expiry date of the lease. This one partially continued lease is now held by our Company for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases. On August 19, 2019, 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where we determined that there was no or limited exploitable resources; and

(iii) 53,163 ~~sections~~gross ofacres ~~land~~(3,163 net acres) under one oil sands lease are set to expire on April 9, 2024. It is our Company’s opinion that we have already met the governmental requirements for this lease, and we will be applying to continue ~~all 5 sections of~~ this lease into perpetuity.

9Escalating yearly rents can be offset by eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease.

~~Delivery~~Summary ~~Commitments~~of Oil and Gas Reserves

We ~~are~~did not ~~subject~~have toour ~~any~~properties ~~obligations~~independently ~~under~~assessed ~~existing~~and ~~delivery~~evaluated ~~commitment~~for ~~contracts~~reserves orand ~~agreements~~resources ~~calling~~as ~~for~~of ~~the~~September ~~provision~~30, 2019. As of ~~fixed~~September 30, 2015, DeGolyer and ~~determinable~~MacNaughton ~~quantities~~Canada ofLimited ~~oil~~(“DeGolyer”) in compliance with SEC definitions and ~~gas~~guidance and in accordance with generally accepted petroleum engineering principles, did assess and evaluate our properties for reserves and resources. Our Company reported no proved reserves as of September 30, 2015.

Disclosure of Reserves

We did not have our properties independently assessed and evaluated for reserves and resources as of September 30, 2018.

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

We did not have our properties independently assessed and evaluated for reserves and resources as of September 30, 2018. Our properties were last 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 last 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

We did not have our properties independently assessed and evaluated for reserves and resources as of September 30, 2018.

Proved Undeveloped Reserves

We did not have our properties independently assessed and evaluated for reserves and resources as of September 30, 2018. 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

We did not have our properties independently assessed and evaluated for reserves and resources as of September 30, 2018. 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.

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. A majority of the Joint Venture partners voted to temporarily suspend operations for 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:

	Oil - Bitumen
	Production(1)		Average Sales Price per Unit		Average Production Costs per Unit
Fiscal Year	(bbls)		($/bbl)		($/bbl)
Peace River Oil Sands, Alberta, Canada:
2018		–	$	–	$	–
2017		–	$	–	$	–
2016		19,156	$	7.91	$		(2)
2015		25,737	$	23.68	$		(2)

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

(2) 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

As of the fiscal years ended September 30, 2018 and 2017 all of our producing wells were 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, ~~2018~~2019, ~~2017,~~2018 ~~2016,~~ and ~~2015~~2017.

Development (Net Wells)

Exploratory (Net Wells)

~~Total~~

Oil

Gas

Service Well

Dry

Oil

Gas

Service Well

Dry

~~Net wells~~

2018

September 30, 2019

Alberta, Canada

–

2017

September 30, 2018

Alberta, Canada

–

~~0.25~~*

–

~~0.25~~

2016

September 30, 2017

Alberta, Canada

–

–0.25

–

2015

Alberta, Canada

–

* - On February 15, 2018, we entered into a contribution agreement with a third-party to drill a well on one of our Sawn Lake oil sands leases in which we acquired cores and logs through the Bluesky formation, but did not acquire a working interest in that well.

Productive Wells

As of the fiscal year ended September 30, 2019 all of our producing wells were shut-in in February 2016.

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

OnCurrently ~~February~~we 15have no wells in the process of being drilled. Our Company to date has, ~~2018~~but not limited to, wedrilled or participated in 13 wells over our Sawn Lake leases to expand the boundaries of the Bluesky oil sands reservoir; commissioned various independent reservoir simulation studies of our properties; successfully produced bitumen from the SAGD Project, which outperformed independent reservoir production type curves; acquired AER approval for two thermal recovery projects, which includes our joint SAGD Project facility expansion to produce up to 3200 bopd; successfully entered into aFarmout ~~contribution~~Agreements; ~~agreement~~and ~~with~~over athe ~~third-party~~last 3 years we have successfully applied to ~~drill~~the aAER ~~well~~to oncontinue ~~one~~the best sections of our ~~Sawn~~oil ~~Lake~~sands properties past their initial expiry dates, where resources were identified. Under the oil sands lease continuation regulations an operator or leaseholder must demonstrate certain levels ~~leases~~of inexploration ~~which~~and wedevelopment ~~acquired~~by ~~cores~~providing the AER with drilling, coring and ~~logs~~seismic ~~through~~data within a certain timeframe in order to maintain the ~~Bluesky~~lease ~~formation~~past its expiry date.

~~In August of 2017, we jointly participated in drilling one well on our Sawn Lake properties. This well was drilled to a total depth of 681 meters.~~8

~~Currently~~We weare ~~have~~focused noon ~~wells~~developing in the ~~process~~bitumen ofresources ~~being~~located ~~drilled.~~on ~~However,~~our weSawn ~~have~~Lake 11properties ~~exploratory~~using ~~wells~~thermal recovery technology development. A SAGD Project on our Sawn Lake ~~oil~~properties ~~sands~~commenced ~~properties that~~in 2013 where we ~~previously~~have a 25% working interest. The SAGD Project consists of one SAGD well pair drilled to a depth of 650 meters and ~~completed~~a ~~which~~horizontal ~~are~~length ~~currently~~of ~~suspended~~780 meters and the SAGD facility for steam generation, water handling, and bitumen treating. ~~And~~Steam injection commenced in ~~addition~~May to2014 ~~the~~and 11production ~~exploratory~~commenced ~~wells~~on September 16, we2014. ~~also~~The SAGD ~~have~~Project reached a steady state production level in February of 2016 of 620 bopd, on a 100% basis (155 bopd net to us) from one SAGD well pair ~~which~~and isachieved an instantaneous Steam oil Ratio (“ISOR”) efficiency of 2.1, demonstrating the productive capability of our Sawn Lake reservoir with significant future potential value. The lower the ISOR the lower the production costs and emissions per barrel of oil produced. The production results of the current SAGD Project successfully confirmed the capability of the Bluesky reservoir to produce using thermal recovery technology. A majority of our Company’s Joint Venture partners voted to temporarily ~~shut-in~~suspend operations for the SAGD Project at the end of February 2016.

AsThe ~~previously~~successful ~~disclosed,~~results onof ~~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~~were ofused ~~one SAGD well pair drilled~~ to anupdate ~~approximate~~our ~~depth~~reservoir ofmodels ~~650 meters~~ and a ~~horizontal~~will ~~length~~be ofused ~~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~~preparation ~~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~~updated ~~production~~independent ~~results~~evaluation of ~~the current SAGD Project successfully confirmed the capability of the Bluesky reservoir to produce using thermal recovery technology. A majority of~~ our ~~Company’s~~Sawn ~~Joint~~Lake ~~Venture partners voted to temporarily suspend operations for the SAGD Project at the end of February 2016~~properties.

InRegulatory ~~early~~approval ~~May of 2016, an amended application~~ was ~~submitted~~received toin ~~the~~December ~~AER~~2017 for ana commercial expansion of the existing SAGD Project facility site ~~which~~ ~~would~~where ~~potentially~~we ~~increase~~have ~~the operations up to~~ a ~~total~~25% working ~~of eight SAGD well pairs~~interest. ~~The~~This ~~amended~~expansion application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs will need to be ~~needed~~operating to achieve this production level. The ~~AER~~SAGD Project ~~approval~~development ~~for~~plan ~~the~~will ~~expansion~~be done in stages to reduce initial financial costs. The first stage anticipates the reactivation of the existing SAGD ~~Project~~facility ~~was~~and ~~granted~~existing ~~on December~~SAGD 15well pair, ~~2017.~~along ~~Currently,~~with the drilling of one additional SAGD ~~Project~~well ~~continues~~pair, toinitially producing ~~move~~from ~~forward~~two ~~with~~SAGD ~~engineering~~well ~~and~~pairs. ~~identification~~The ofsecond ~~long~~stage ~~lead~~anticipates ~~time items~~drilling ~~towards~~an ~~potential~~additional ~~expansion~~three SAGD well pairs to produce up to 3,200 bopd and ~~future~~the ~~development~~expansion atof ~~Sawn~~the ~~Lake~~existing SAGD facility to generate the additional steam required. The ~~SAGD~~lead ~~Project~~time ~~expansion~~to acquiring the necessary equipment and commencing operations is ~~dependent~~estimated ~~on,~~to be about 18 months and another 6 months is required for the ~~numerous~~start ~~factors~~of ~~including~~bitumen ~~but~~production ~~not~~(after ~~limited~~development toof the steam chamber). As of June 30, 2019, a Sawn Lake full field development plan using SAGD batteries has been defined by the ~~approval~~operator of the SAGD Project. We and our joint venture partners continue to move forward with SAGD Project with completing detailed engineering and assessing potential marketing arrangements for the commercial development expansion to 3,200 bopd.

~~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 1211 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, ~~the~~and ~~Farmee~~continues ~~has~~to ~~since~~be ~~reimbursed~~funded ~~our~~by ~~Company and/or paid~~ the ~~operator approximately $20~~agreement.8 ~~million~~The ~~($27.0~~Farmee ~~million~~shall ~~Cdn)~~also incontinue to ~~total~~cover ~~for~~our ~~the Farmee~~Company’s ~~share~~administrative ~~and our share of the capital~~ costs ~~and operating expenses of the SAGD Project~~ up to ~~September~~ $30,000 ~~2018.~~per ~~These~~month ~~costs~~until ~~include the drilling and~~ completion ofin ~~one~~all ~~SAGD well pair;~~substantial ~~the~~respects ~~purchase and transportation~~ of ~~equipment of which included~~ the ~~once~~SAGD ~~through~~Project ~~steam~~agreement ~~generator~~entered ~~(“OTSG”),~~into ~~production tanks,~~on ~~water~~July ~~treatment plant~~30, ~~and~~2013 ~~power~~between ~~generators; installation and construction of~~ the ~~steam~~Company ~~plant facility; testing~~ and ~~commissioning;~~ the ~~purchase~~operator of the water source and disposal wells and expenditures to connect these water wells with pipelines to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD ~~facility~~ ~~site; and the monthly operating expenses associated with the steaming and production of the SAGD well pair up to September 30, 2018~~Project.

12The development progress of our Sawn Lake oil sands properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can, and often, do delay development of similar projects and our projects. Because of these and other factors, our oil sands projects can take significantly longer to complete than regular conventional drilling programs for lighter oil. To date, our geological, engineering, economic studies, and our SAGD Project production results lead us to believe that our working interest can support future full profitable commercial production.

~~Currently,~~We wepreviously ~~have~~received inapproval ~~place~~from ~~joint~~the ~~operating~~AER ~~agreements~~for ~~(our~~a ~~“Joint~~horizontal ~~Operating~~cyclic ~~Agreements”)~~steam ~~with~~stimulation ~~our~~project ~~joint~~(“HCSS ~~venture~~Project”) ~~partners to~~application. ~~manage~~It ~~the~~is ~~operations~~anticipated ofthat ~~our~~we ~~joint~~will ~~oil~~develop ~~sands~~a ~~leases.~~thermal ~~Under~~demonstration ~~these~~project ~~agreements~~on our ~~joint~~properties ~~oil~~followed ~~sands~~by ~~leases~~a ~~were~~commercial ~~evaluated~~expansion ~~seismically,~~project ~~geologically~~on ~~and~~one byhalf ~~drilling~~section toof ~~establish~~land ~~the~~located ~~continuity~~on ~~and~~section ~~the~~10-92-13W5 ~~distribution~~ of ~~the crude bituminous-bearing Bluesky reservoir zone across~~ our ~~joint~~Sawn ~~lands.~~Lake ~~The~~oil ~~development~~sands ~~progress of our~~ properties iswhere ~~governed~~we bycurrently ~~several~~have ~~factors~~a ~~such as federal and provincial~~90% ~~governmental~~working ~~regulations~~interest. ~~Long~~The ~~lead~~final ~~times~~performance inresults ~~getting~~and ~~regulatory~~revised ~~approval~~reservoir ~~for~~modeling ~~thermal~~studies ~~recovery~~from ~~projects are commonplace in~~ our ~~industry.~~current ~~Road~~SAGD ~~bans,~~Project ~~winter~~will ~~access~~be ~~only~~used ~~roads~~to ~~and~~fine-tune ~~environmental~~our ~~regulations~~HCSS ~~can~~Project ~~and~~facility ~~often~~design dobefore ~~delay~~we ~~development~~initiate ofstart-up ~~similar~~operations ~~projects.~~on ~~Because~~the half section of ~~these~~land ~~and~~where ~~other~~we ~~factors,~~plan ~~our~~to ~~oil~~drill ~~sands~~two ~~project~~horizontal ~~can~~wells ~~take~~to ~~significantly~~test ~~longer~~the touse ~~complete~~of ~~than~~HCSS ~~regular~~technology. ~~conventional~~We performed an ~~drilling~~environmental ~~programs~~field ~~for~~study ~~lighter~~and ~~oil.~~surveyed Tothe ~~date,~~proposed ~~our~~location ~~geological,~~of ~~engineering~~our ~~and~~planned ~~economic~~HCSS ~~studies~~Project ~~lead~~site usand toreceived ~~believe~~AER ~~that~~approval ~~our~~for ~~working~~the ~~interest~~surface ~~can~~wellsite ~~support~~and ~~future~~access ~~full~~road ~~profitable~~for ~~commercial~~this ~~production~~project.

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 received AER approval for the surface wellsite and access road for this project.

ITEM 3.

LEGAL PROCEEDINGS

WeOn ~~are~~October ~~not~~28, ~~aware~~2019, ofProvident ~~any~~Premier ~~material~~Master ~~pending~~Fund ~~legal~~Ltd. ~~actions~~(the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”) in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim had been filed on November 1, 2018 but had never been served so our Company was not aware of it.

The Plaintiff claims that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all petroleum substances produced, saved and marketed from six of our oil sands leases located within our Sawn Lake properties. The Plaintiff further claims that on September 22, 2006, Nearshore and Gemini Strategies LLC (“Gemini”) entered into a royalty conveyance agreement whereby Nearshore sold 1% of the GORR to Gemini. The Plaintiff further states that Gemini acquired the 1% GORR as agent for Provident, Grey K Fund LP (“Grey K”) and Grey K Offshore Fund Ltd. (“Grey K Offshore”). The Plaintiff further claims that on September 22, 2006, Gemini delivered a notice of assignment, in accordance with the Canadian Association of Petroleum Landmen Assignment Procedure (the “1993 CAPL”), to the grantors of the 1% GORR, novating Provident (66.67%, net 0.6667%) Grey K (19.33%, net 0.1933%) and Grey K Offshore (14%, net 0.14%) into the GORR agreement. The Plaintiff further claims that on September 2, 2009, any legal title in the GORR beneficially owned by Grey K and Grey K Offshore vested in the Crown in right of Alberta pursuant to Section 229(1) of the Business Corporations Act and pursuant to section 15 of the Unclaimed Personal Property and Vested Property Act. The Plaintiff further claims that the GORR was payable by one or more of the Defendants to Provident and that the Defendants are in breach of the GORR agreement by failing to pay the GORR. Despite the allegation within the claim that the GORR was payable to each of Provident, Grey K and Grey K Offshore, the only Plaintiff named in the Amended Statement of Claim is Provident and relief is only being sought by Provident in relation to its purported 0.67% interest.

The Plaintiff seeks: 1) A declaration that the Plaintiff is the legal owner of 0.67% of the GORR payable on all oil sands produced from the lands which is payable by one or more of the Defendants; 2) An accounting to determine the amount of the outstanding royalty of which judgment is estimated by the Plaintiff to be in the amount of $100,000 Cdn; and 3) Interest and costs.

Our Company continues to deny the validity of the Purported 6.5% Royalty in the first instance. As well, if the Purported 6.5% Royalty was valid, which is denied, it was not a gross overriding interest, but rather an overriding interest, which allowed for the deduction of operating and marketing costs. See Item 1 “Business” under the heading “Royalty Agreements” in this annual report on Form 10-K. We plan to vigorously defend ourselves against the Plaintiff’s claims.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

1310

PART II

ITEM 5.

MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Deep Well’s stock is currently quoted on the OTC Marketplace under the trading symbol DWOG. The following table sets forth the high and low sales prices for Deep Well common stock as reported on the OTC Marketplace for the fiscal years indicated below. These over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions:

	High		Low
	High*		Low*
Fiscal September 30, 2015
First Quarter	$	0.34	$	0.12
Second Quarter	$	0.20	$	0.06
Third Quarter	$	0.12	$	0.07
Fourth Quarter	$	0.16	$	0.07
Fiscal September 30, 2016
First Quarter	$	0.09	$	0.03
Second Quarter	$	0.04	$	0.02
Third Quarter	$	0.07	$	0.03
Fourth Quarter	$	0.07	$	0.03
Fiscal September 30, 2017
First Quarter	$	0.06	$	0.02
Second Quarter	$	0.03	$	0.02
Third Quarter	$	0.05	$	0.01
Fourth Quarter	$	0.03	$	0.02
Fiscal September 30, 2018
First Quarter	$	0.04	$	0.01
Second Quarter	$	0.05	$	0.03
Third Quarter	$	0.08	$	0.04
Fourth Quarter	$	0.06	$	0.03
Fiscal September 30, 2019
First Quarter	$	0.05		0.02
Second Quarter	$	0.06		0.01
Third Quarter	$	0.04		0.01
Fourth Quarter	$	0.05		0.01

*Source: OTC Markets

Holders of Record

As of September 30, ~~2018~~2019, we had approximately ~~139~~141 holders of record of our shares of common stock. Our Company estimates that investment dealers and other nominees are the record holders for approximately 1,839 beneficial holders.

Dividends

We have not paid cash dividends since inception. 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.

1411

Securities Authorized for Issuance under Equity Compensation Plans

The following table provides information as of September 30, ~~2018~~2019 with respect to shares of Deep Well’s common stock that may be issued under our existing equity compensation plans.

Equity Compensation Plan

Plan Category

(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights

(b) Weighted-average exercise price of outstanding options, warrants and rights

(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))

Equity compensation plans approved by security holders

8600,~~080,~~000

(1)

0.3623

1422,~~977~~457,460

(2)

Equity compensation plans not approved by security holders

–

Total

8600,~~080,~~000

0.3623

1422,~~977~~457,460

(2)

(1) 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. These shares expired unexercised on November 17, 2019.

(2) Based on 230,574,603 issued and outstanding shares as at September 30, ~~2018~~2019. The maximum number of common shares that may be reserved for issuance under the Stock Option Plan (as defined below), as amended, may not exceed 10% of our Company’s issued and outstanding common shares.

Stock Option Plan

On November 28, 2005 and as amended on December 4, 2013, our Board adopted the Deep Well Oil & Gas, Inc. stock option plan (the “Stock Option Plan”). The Stock Option Plan was approved by a majority of our shareholders at the February 24, 2010 general meeting of shareholders. The Stock Option Plan, which is administered by our Board, permits options to acquire shares of Deep Well’s common stock to be granted to our directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons providing services to our Company. This Stock Option Plan was adopted to provide an incentive to the retention of our directors, officers and employees as well as consultants that we may wish to retain in the future. The maximum number of shares of common stock, which may be reserved for issuance under the Stock Option Plan may not exceed 10% of our issued and outstanding common stock, subject to adjustment as contemplated by the Stock Option Plan. For further information see ~~Note 12 in~~ the notes to our consolidated financial statements contained herein.

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, ~~2018~~2019.

ITEM 6.

SELECTED FINANCIAL DATA

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and therefore are not required to provide the information required under this item.

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ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. For the purpose of this discussion, unless the context indicates another meaning, the terms: “Deep Well,” “Company,” “we,” “us,” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries. This discussion includes forward-looking statements that reflect our current views with respect to future events and financial performance that involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding – Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors” and “Environmental Laws and Regulations” ~~disclosed~~as disclosed in ~~this~~our Annual Report on Form 10-K filed with the Alberta Securities Commission (“ASC”) on SEDAR on January 13, 2020 and the U.S. Securities and Exchange Commission (“SEC”) on January 13, 2020. Our Annual Report on Form 10-K can be downloaded from our website at www.deepwelloil.com.

Our consolidated financial statements and the supplemental information thereto are reported in United States dollars and are prepared based upon United States generally accepted accounting principles (“U.S. GAAP”). References in this Annual Report on Form 10-K to “$” are to United States dollars and references to “Cdn$” are to Canadian dollars. On ~~November~~January 263, ~~2018~~2020, the daily rate of exchange for Cdn$, expressed in US$ was Cdn$1.00 = US$0.~~7559~~7699 as reported by the Bank of Canada.

General Overview

Deep Well Oil & Gas, Inc., along with its subsidiaries through which it conducts business, is an independent junior oil sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base where we have working interests ranging from 25% to 100% in the Peace River oil sands area of Alberta, Canada. Our principal office is located at Suite 700, 10150 - 100 Street NW, Edmonton, Alberta, Canada T5J 0P6, our telephone number is (780) 409-8144, and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com. Our financial statements are available for download on our website or you may download our financial statements from the U.S. Securities and Exchange Commission’s website at www.~~DWOG~~sec.~~com~~gov. The contents of our website are not part of the Annual Report on Form 10-K for the fiscal year ended September 30, ~~2018~~2019.

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, drilling, testing and analyzing of wells to define our oil sands reservoir, and development planning of our Alberta Energy Regulatory (“AER”) approved thermal recovery projects, which includes our steam assisted gravity drainage project where we have a 25% working interest. The following table sets forth summarized financial information:

	September 30,			September 30,
	2018			2017
Revenue	$	–		$	–
Provincial royalty expenses		–			–
Revenue, net of royalty		–			–
Expenses
Operating expenses		148,046			142,169
Operating expense covered by Farmout		(148,046	)		(142,169	)
General and administrative		289,209			222,252
Depreciation, accretion and depletion		56,032			76,938
Net loss from operations		(345,241	)		(299,190	)
Other income and expenses
Rental and other income		9,054			2,575
Interest income		6,056			3,517
Net loss and comprehensive loss	$	(330,131	)	$	(293,098	)

First production from our present joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began on September 16, 2014. A majority of our Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016. In accordance with the Farmout Agreement we entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project in return for a net 25% working interest in two oil sands leases where we had a working interest of 50% before the execution of the Farmout Agreement. 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. Our net operating margin after operating expenses is zero, under the Farmout Agreement, any negative operating cash flows are reimbursed to us to fund our share of the SAGD Project. Therefore, the total share of the capital costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, as of September 30, 2018, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $20.8 million ($27.0 million Cdn) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project. These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator, production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the one SAGD well pair; and the expenses associated the monthly shut-in operations of the SAGD Project facility.

For the year ended September 30, 2018, our general and administrative expenses increased by $66,957 compared to the year ended September 30, 2017. This was a 30.1% increase from the 2017 fiscal year which was primarily due to an increase of $56,863 in engineering fees. We also received $360,000 during the current fiscal year from the Farmee in accordance with a Farmout Agreement to offset some of our monthly expenses.

For the year ended September 30, 2018, our share-based compensation expense was $Nil compared to $2,314 for the year ended September 30, 2017. After adjusting out the non-cash items for share-based compensation and foreign exchange, and the funds we received from the Farmee, our general and administrative expenses were $643,080 for the year ended September 30, 2018 compared to $598,219 for the year ended September 30, 2017.

For the year ended September 30, 2018, our depreciation and accretion expense decreased by $20,906 compared to the year ended September 30, 2017, 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, 2018, our rental and other income increased by $6,479 compared to the year ended September 30, 2017.

As a result of the above transactions, our net loss and loss from operations for the year ended September 30, 2018 increased by $37,033 compared to the year ended September 30, 2017. As discussed above this increase was primarily due to the increase in engineering fees.

Operations

~~The~~Since ~~first~~the ~~SAGD~~inception ~~well~~of ~~pair,~~our ~~for~~current ~~the~~business ~~SAGD Project~~plan, ~~was~~our ~~drilled~~operations tohave aconsisted ~~vertical depth~~ of ~~approximately~~various ~~650~~exploration ~~meters with a horizontal length of 780 meters each. Steam injection commenced in May 2014~~ and ~~production~~start-up ~~started~~activities ~~in September of 2014. Production from this one~~relating ~~SAGD~~to ~~well~~our ~~pair~~properties, ~~increased~~including ~~significantly over~~ the ~~18-month~~acquisition ~~period~~of itlease ~~produced.~~holdings, ~~Over~~raising ~~January~~capital, ~~and~~locating ~~February~~joint ofventure ~~2016~~partners, ~~production~~acquiring ~~from~~and ~~the~~analyzing ~~SAGD~~seismic ~~Project averaged 615 bopd~~data, oncomplying awith ~~100%~~environmental ~~basis~~regulations, ~~(154 bopd net to us)~~drilling, ~~with~~testing anand ~~average~~analyzing ~~SOR~~ of ~~2.1~~wells ~~from~~to ~~one~~define ~~SAGD~~our ~~well~~oil ~~pair.~~sands ~~The~~reservoir, ~~SOR~~and isdevelopment ~~reflective~~planning of ~~the~~our ~~amount~~Alberta ofEnergy ~~steam~~Regulatory ~~needed~~(“AER”) toapproved ~~produce~~thermal ~~one~~recovery ~~barrel~~projects, ~~of oil. This SAGD Project was temporarily suspended~~which atincludes ~~the~~our ~~end~~joint ofSteam ~~February~~Assisted ~~2016.~~Gravity ~~The~~Drainage ~~capital~~Demonstration ~~costs~~Project of (the ~~existing~~ “SAGD Project ~~steam plant facility, with pipelines and one SAGD~~”) ~~well~~where ~~was~~we ~~approximately~~have ~~$26.5 million (Cdn $34.8 million) on~~ a ~~100~~25% 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.~~

~~The~~Our ~~current~~main objective is to develop our oil sands lease holdings located in the Peace River oil sands area of North Central Alberta, Canada (also known as our Sawn Lake oil sands properties) using thermal recovery technologies. Currently, we have received approval from the AER for two thermal recovery projects located on our Sawn Lake properties. To date, our geological, engineering, economic studies, and our SAGD Project ~~has:~~production results lead us to believe that our working interest can support future full profitable commercial production.

A SAGD Project on our Sawn Lake properties commenced in 2013 where we have a 25% working interest. The SAGD Project consists of one SAGD well pair drilled to a depth of 650 meters and a horizontal length of 780 meters and the SAGD facility for steam generation, water handling, and bitumen treating. Steam injection commenced in May 2014 and production started in September of 2014. The SAGD Project reached a steady state production level in February of 2016 of 620 bopd, on a 100% basis (155 bopd net to us) from one SAGD well pair and achieved an instantaneous Steam oil Ratio (“ISOR”) efficiency of 2.1, demonstrating the productive capability of our Sawn Lake reservoir with significant future potential value. The lower the ISOR the lower the production costs and emissions per barrel of oil produced. A majority of our Company’s Joint Venture partners voted to temporarily suspend operations for the SAGD Project at the end of February 2016.

The SAGD Project has:

●

confirmed that the SAGD process works in the Bluesky formation at Sawn Lake;

●

established characteristics of ramp up through stabilization of SAGD performance;

● indicated the productive capability and ~~SOR~~ISOR of the reservoir; and

●

provided critical information required for well and facility design associated with future commercial development.

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The production results of the SAGD Project successfully confirmed the capability of the Bluesky reservoir to produce using thermal recovery technology. The following graph sets out the production levels that the SAGD Project achieved. These production numbers ~~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.

~~It is anticipated that a reactivation of the existing SAGD Project facility and current SAGD well pair will be part of a potential commercial expansion.~~ In early May of 2016, an amended application was submitted to the AER for ana commercial expansion of the existing SAGD Project facility site ~~which~~and ~~would~~received ~~potentially~~regulatory ~~increase~~approval ~~the~~in ~~operation~~December ~~for up to a total of eight SAGD well pairs~~2017. This expansion application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs will need to be operating to achieve this production level. The ~~expanded~~SAGD ~~facility~~Project development plan will be ~~designed~~done in stages to reduce initial financial costs. The ~~handle~~first stage anticipates the reactivation of the existing SAGD facility and existing SAGD well pair, along with the drilling of one additional SAGD well pair, initially producing from two SAGD well pairs. The second stage anticipates drilling an additional three SAGD well pairs to produce up to 3,200 bopd and the expansion of the existing SAGD facility to generate the additional steam required. The ~~AER~~lead ~~approval~~time to acquiring the necessary equipment and commencing operations is estimated to be about 18 months and another 6 months is required for ~~this~~the ~~expansion~~start of bitumen production (after development of the steam chamber). We anticipate our ~~existing~~near- and ~~SAGD~~long-term ~~Project~~funding ~~was~~of ~~granted~~our operations to be financed through the existing Farmout Agreement, future earn-in ~~December~~agreements, and cash flow from the reactivation of ~~2017~~the existing SAGD Project. ~~While~~We also intend to negotiate with the Petroleum and Natural Gas holders in the ~~joint~~area ~~venture~~of ~~has~~our ~~not~~leases, ~~yet~~to ~~approved~~enter into further downhole contribution agreements to ~~expand~~acquire ~~the~~additional ~~SAGD~~logs ~~Project~~and ~~facility~~cores of the Bluesky formation, ~~currently~~in order to expand the ~~SAGD~~boundaries ~~Project~~of ~~continues~~the oil sands reservoir we have already defined and save on drilling costs and reduce our environmental footprint. We and our joint venture partners continue to move forward with SAGD Project with completing detailed engineering and ~~identification~~assessing ofpotential ~~long~~marketing ~~lead~~arrangements ~~time~~for ~~items~~the ~~towards~~commercial ~~potential~~development expansion to 3,200 bopd ~~and~~(100% basis). ~~future~~As ~~commercial~~of ~~development at~~June 30, 2019, a Sawn Lake full field development plan using SAGD batteries has been defined by the operator of the SAGD Project.

In August of 2017, we jointly participated in drilling one well on our Sawn Lake properties. This well was drilled to a total depth of 681 meters.

On February 15, 2018, we entered into a contribution agreement with a third-party, whereby we paid a cash contribution to drill and acquire cores and logs through the Bluesky formation from a well drilled by a third-party on one of our oil sands leases.

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

Our Company’s oil sands acreage as of September 30, 2018, covers 37,322 gross acres (29,383 net acres) of land under nine oil sands leases. Until our Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of our Company’s nine oil sands leases are as follows:14

~~(iv) Of our~~ Our Company’s ~~acreage,~~to ~~20,242~~date ~~gross acres (13~~has,~~284~~ ~~net~~but ~~acres)~~not ~~under~~limited ~~five oil sands leases were set~~ to, ~~expiry~~drilled onor ~~July~~participated ~~10,~~in ~~2018.~~13 Inwells ~~November~~over ~~of 2017,~~ our ~~Company’s~~Sawn ~~joint~~Lake ~~venture~~leases ~~partner~~to ~~and~~expand ~~operator~~the boundaries of ~~two~~the ofBluesky ~~these five~~ oil sands ~~leases,~~reservoir; ~~submitted~~commissioned ~~two~~various ~~continuation~~independent ~~applications~~reservoir tosimulation ~~the~~studies ~~Alberta~~of ~~Oil~~our ~~Sands~~properties; ~~Tenure~~successfully produced ~~division~~bitumen tofrom ~~apply~~the toSAGD ~~continue 7~~Project,~~591~~ ~~gross~~which ~~acres~~outperformed ~~(1,898~~independent ~~net~~reservoir ~~acres)~~production ~~and~~type oncurves; ~~January~~acquired ~~29,~~AER ~~2018,~~ approval for ~~was~~two ~~received~~thermal ~~from~~recovery ~~Alberta Energy to continue 6~~projects,~~958~~ ~~gross~~which ~~acres~~includes ~~(1,740~~our ~~net~~joint ~~acres).~~SAGD InProject ~~June~~facility ofexpansion ~~2018,~~to ~~our~~produce ~~Company~~up asto ~~operator~~3200 ofbopd; ~~three~~successfully entered ofinto ~~these~~Farmout ~~five~~Agreements; ~~oil~~and ~~sands~~we ~~leases,~~have ~~submitted~~successfully ~~three~~applied ~~continuation applications~~ to the ~~Alberta~~AER ~~Oil~~to ~~Sands~~continue ~~Tenure~~the ~~division~~best tosections ~~apply~~of toour ~~continue~~oil ~~another~~sands ~~7,591~~properties past ~~gross~~their ~~acres~~initial ~~(6,832~~lease ~~net~~expiry ~~acres)~~dates, where resources were identified. ~~and~~Under onthe ~~July~~oil ~~15,~~sands ~~2018,~~lease ~~approval~~continuation ~~was~~regulations ~~received~~an operator ~~from~~or ~~Alberta~~leaseholder ~~Energy~~must todemonstrate ~~continue~~certain ~~5,693~~levels ~~gross~~of ~~acres~~exploration ~~(5,124~~and ~~net~~development ~~acres).~~by ~~Our~~providing ~~Company~~the ~~has~~AER ~~not~~with ~~yet~~drilling, ~~received~~coring and ~~approval~~seismic ondata ~~one~~within ~~continuation~~a ~~application~~certain ittimeframe ~~submitted~~ in ~~June~~order ofto ~~2018~~maintain tothe ~~continue~~lease ~~another~~past ~~1,898~~its ~~gross~~expiry ~~acres~~date. ~~(1,708~~Our ~~net~~Company’s ~~acres).~~Sawn AsLake oil sands properties under lease as of September 30, ~~2018~~2019, acovers ~~total of 5~~19,~~693~~610 gross acres (413,~~713~~442 net acres) onof ~~five~~land ~~oil~~under seven oil sands leases ~~expired without being continued~~. ~~These~~The ~~expired~~lease ~~lands~~expiration ~~were~~dates ~~primarily~~of ~~areas where~~ our Company’s ~~was~~oil ~~unable~~sands ~~to ascertain exploitable resources. Continued~~ leases ~~have no future expiry dates but~~ are ~~subject~~as ~~to yearly escalating rental payments until they are deemed to be producing leases.~~follows:

181. Out of 20,242 gross acres (13,284 net acres) under five oil sands leases were set to expiry on July 10, 2018, 14,549 gross acres (8,571 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. In November of 2017, our Company’s joint venture partner and operator of two of these five oil sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591 gross acres (1,898 net acres) and in January 2018, approval was received from Alberta Energy to continue 6,958 gross acres (1,740 net acres). In June 2018, our Company as operator of three of these five oil sands leases, submitted three continuation applications to the Alberta Oil Sands Tenure division to apply to continue another 7,591 gross acres (6,832 net acres) where resources were identified and in July 2018 and April 2019, approval was received from Alberta Energy to continue 7,591 gross acres (6,832 net acres). Of these five oil sands leases that were set to expiry on July 10, 2018, a total of 5,693 gross acres (4,713 net acres) expired without being continued. These expired lands were primarily areas where our Company determined that there was no or limited exploitable resources. These continued leases are now held by our Company for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases.

~~(v)~~2. ~~Of our Company’s acreage,~~ 19,610 gross acres (17,649 net acres) under the three most northern oil sands leases ~~are~~were set to expire on August 19, 2019. ~~Our~~In August 2019, our Company ~~intends~~submitted one continuation application to the Alberta Oil Sands Tenure division to apply ~~for~~to acontinue ~~term~~1,898 ~~extension~~acres (1,708 net acres) of the 19,610 gross acres (17,649 net acres) on ~~these~~one ~~three~~of the northern ~~oil~~most ~~sands~~ leases and subsequently in early October 2019 approval was received from Alberta Energy to continue 1,898 ~~however~~gross itacres (1,708 net acres) past the expiry date of the lease. This one partially continued lease is ~~not~~now ~~certain~~held ifby anour ~~extension~~Company ~~will~~for perpetuity, subject to yearly escalating rental payments until they are deemed to be ~~granted~~producing byleases. ~~Alberta~~On ~~Energy~~August 19, 2019, 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where we determined that there was no or limited exploitable resources.

~~(vi)~~3. ~~Of our Company’s acreage,~~ 3,163 gross acres (3,163 net acres) under one oil sands lease are set to expire on April 9, 2024. It is our Company’s opinion that we have already met the governmental requirements for this lease, and itwe will be applying to continue this lease ~~beyond~~into ~~its expiry date~~perpetuity.

The development progress of our Sawn Lake oil sands properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can, and often, do delay development of similar projects and our projects. Because of these and other factors, our oil sands ~~project~~projects ~~could~~can take significantly longer to complete than regular conventional drilling programs for lighter oil.

Results of Operations

The following table sets forth summarized financial information:

	September 30,			September 30,
	2019			2018

Revenue	$	–		$	–
Provincial royalty expenses		–			–
Revenue, net of royalty		–			–

Expenses
Operating expenses		97,643			148,046
Operating expense covered by Farmout		(97,643	)		(148,046	)
General and administrative		165,405			289,209
Depreciation, accretion and depletion		46,036			56,032

Net loss from operations		(211,441	)		(345,241	)

Other income and expenses
Rental and other income		6,612			9,054
Interest income		7,694			6,056

Net loss	$	(197,135	)	$	(330,131	)

There was no production volumes or revenues for the fiscal years ending September 30, 2019 and 2018, due to a majority of our Company’s Joint Venture partners voting to temporarily suspend operations of the SAGD Project at the end of February 2016. In accordance with the Farmout Agreement we entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project in return for a net 25% working interest in two oil sands leases where we had a working interest of 50% before the execution of the Farmout Agreement. Under the terms of the Farmout Agreement the Farmee is required to provide funding to cover the monthly administrative expenses of our Company provided that such funding shall not exceed $30,000 per month. The Farmee shall continue to cover our Company’s administrative costs up to $30,000 per month until completion in all substantial respects of the SAGD Project agreement entered into between the Company and the operator of the SAGD Project. Our net operating margin after operating expenses is zero, under the Farmout Agreement, any negative operating cash flows are reimbursed to us to fund our share of the SAGD Project. Therefore, the total share of the capital costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, as of September 30, 2019, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $20.6 million (Cdn$27.3 million) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project. These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator, production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the one SAGD well pair when the facility was producing; and the expenses associated the monthly shut-in operations of the SAGD Project facility.

For the year ended September 30, 2019, our general and administrative expenses decreased by $123,804 compared to the year ended September 30, 2018, which was primarily due to decreases in engineering, and audit fees. We also received $360,000 during the current fiscal year from the Farmee in accordance with a Farmout Agreement to offset some of our monthly expenses. After adjusting out the non-cash items for foreign exchange loss, and the funds we received from the Farmee, our general and administrative expenses were $523,117 for the year ended September 30, 2019 compared to $643,080 for the year ended September 30, 2018.

For the year ended September 30, 2019, our depreciation and accretion expense decreased by $9,996 compared to the year ended September 30, 2018, which was primarily due to the depreciating value of our assets. Our depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition.

For the year ended September 30, 2019, our rental and other income decreased by $2,442 compared to the year ended September 30, 2018.

As a result of the above transactions, our net loss and loss from operations for the year ended September 30, 2019 decreased by $132,996 compared to the year ended September 30, 2018. As discussed above this decrease was primarily due to the decreases in engineering and audit fees.

Liquidity and Capital Resources

As of September 30, ~~2018~~2019, our total assets were $22,~~827~~677,~~332~~977 compared to $2322,~~033~~827,~~238~~332 as of September 30, 2017. This decrease of $205,906 is primarily due to a cash contribution of $395,500 ($500,000 Cdn) we paid to a third-party, who was drilling into a deeper formation, to drill and acquire cores and logs through the Bluesky formation on our oil sands leases. As of September 30, 2018~~, we had no long-term third-party debt other than our estimated asset retirement obligations on oil and gas properties~~.

~~For~~As ~~the~~of ~~year ended~~ September 30, ~~2018~~2019, ~~we performed an assessment of~~ our ~~carrying~~total ~~costs~~liabilities ofwere ~~our~~$571,384 ~~unproven~~compared ~~oil~~to ~~sands~~$538,604 ~~properties and determined that no write-down of our oil and gas properties~~ as of September 30, 2018. There was ~~necessary.~~no Nosignificant ~~write-downs~~change ofin our ~~unproven~~total ~~oil~~liabilities ~~sands properties~~from ~~were recorded in~~ the ~~year ended~~ September 30, ~~2017.~~2018 ~~However,~~year ~~our unproven oil sands properties may be at risk for future ceiling test write-downs~~end. It is potentially possible that future 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.

AsFor ofthe year ended September 30, ~~2018~~2019, ~~our~~we ~~total~~performed ~~liabilities~~an ~~were~~assessment ~~$538,604 compared to $659,563 as~~ of ~~September~~our ~~30,~~carrying ~~2017.~~costs ~~This decrease~~ of ~~$120,959 in~~ our ~~total~~unproven ~~liabilities~~oil ~~was~~sands ~~primarily~~properties ~~due~~and todetermined that ano ~~decrease~~write-down of ~~outstanding~~our ~~accounts~~oil ~~payable~~and togas ~~the~~properties ~~operator~~as of ~~the~~September ~~SAGD Project for operating expenses~~30, ~~which~~2019 was ~~subsequently~~necessary. ~~reimbursed~~No towrite-downs usof byour ~~the~~unproven ~~Farmee,~~oil insands properties ~~accordance~~were ~~with~~recorded in the ~~terms~~year ofended ~~the~~September ~~Farmout~~30, ~~Agreement~~2018.

Our working capital is as follows.

	September 30, 2018		September 30, 2017
	September 30, 2019		September 30, 2018
Current Assets	$	~~363~~167,~~891~~379	$	1363,~~215,019~~891
Current Liabilities		4570,~~137~~992		~~166~~45,~~152~~137
Working Capital	$	~~318~~96,~~754~~387	$	1318,~~048,867~~754

As of September 30, ~~2018~~2019, our Company had working capital of $~~318~~96,~~754~~387 compared to our working capital of $1318,~~048,867~~754 as of September 30, ~~2017~~2018. This decrease is mainly due to cash used for general and administrative expenses~~, and the cash contribution of $395,500 ($500,000 Cdn) we paid to a third-party operator as described above~~.

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, ~~2018~~2019, we recorded $3238,~~832~~213 in accounts payable due to the operator for our working interest share of the outstanding monthly operating expenses of the SAGD Project, of which all is reimbursable by the Farmee in accordance with the Farmout Agreement. Therefore, this amount is also recorded in accounts receivable to be paid to us from the Farmee to cover our share of the costs of the SAGD Project.

As reported on our Consolidated Statement of Cash Flows under “Operating Activities”, for the year ending September 30, 2018, our net cash used in operating activities was $343,396 compared to $159,509 for the year ended September 30, 2017. This increase of $183,887 was primarily the result of an increase in operating expenses, which included engineering fees and legal fees.16

As reported on our Consolidated Statement of Cash Flows under “~~Investing~~Operating Activities”, wefor ~~had~~the anyear ~~increase~~ending ofSeptember ~~$557~~30,~~436~~ in2019, ~~the investment in~~ our ~~oil~~net ~~and~~cash ~~gas~~used ~~properties~~in ~~for~~operating ~~the~~activities ~~year~~was ~~ended September 30~~$177,258 ~~2018,~~ compared to $343,396 for the year ended September 30, ~~2017~~ 2018. This ~~increase~~decrease isof ~~primarily~~$166,138 ~~due~~was toprimarily the ~~cash~~result ~~contribution~~ of ~~$395,500~~a ~~($500,000~~decrease ~~Cdn)~~in operating weexpenses, ~~paid~~which toincluded aengineering ~~third-party~~fees ~~operator~~and ~~as described~~audit ~~above~~fees.

19As reported on our Consolidated Statement of Cash Flows under “Investing Activities”, we had a decrease of $612,839 in the investment in our oil and gas properties for the year ended September 30, 2019, compared to the year ended September 30, 2018. This decrease is primarily due to the cash contribution of $395,500 (Cdn$500,000) we paid in February 2018 to a third-party operator who was drilling into a deeper formation below our properties, to drill and acquire cores and logs for us through the Bluesky formation on one of our oil sands leases.

As reported on our Consolidated Statement of Cash Flows under “Financing Activities”, for the year ended September 30, ~~2018~~2019 and September 30, ~~2017~~2018, we received $15,000 from one of our directors for the exercise of his stock options. We also had ana ~~increase~~decrease of $245,184 compared to the year ended September 30, ~~2017~~2018. This ~~increase~~decrease is due to a $245,184 refund we received in June 2018, which was related to a return of capital distribution our Company issued in September of 2013.

Our cash and cash equivalents for the year ending September 30, ~~2018~~2019 were $~~298~~49,~~241~~715 compared to $1298,~~097,651~~241 in the year ending September 30, ~~2017~~2018. This decrease of $~~799~~248,~~410~~526 in cash was primarily due to general and administrative expenses~~, and the cash contribution of $395,500 ($500,000 Cdn) paid to a third-party operator as described above, offset by the $245,184 distribution refund received as described above~~. ~~As of September 30, 2018, we had no long-term debt other than our estimated asset retirement obligations on our oil and gas properties.~~

~~Our~~As 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~~September ~~equity securities~~30, ~~debt~~2019, ~~or entering into another form of joint venture. We also note that if~~ we ~~issue~~had ~~more~~no ~~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~~debt ~~and~~other ifthan ~~so,~~our weestimated ~~may~~asset beretirement ~~forced~~obligations toon ~~delay~~ our ~~business~~oil ~~plans~~and ~~until~~gas ~~adequate funding is obtained~~properties.

Our current SAGD Project capital and operating costs are covered under the terms of the Farmout Agreement. As described above the Farmee shall continue to cover our administrative costs up to $30,000 per month, under the Farmout Agreement, until completion in all substantial respects of the SAGD Demonstration Project agreement entered into between us and the operator of the SAGD Project. For our long-term operations, we anticipate that, among other alternatives, we may raise funds during the next twenty-four months through sales of our equity securities, debt, or entering into another form of joint venture. We also note that if we issue more shares of our common stock, our stockholders will experience dilution in the percentage of their ownership of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so, we may be forced to delay our business plans until adequate funding is obtained.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Cautionary Note Regarding Forward-Looking Statements

This Annual Report, including all referenced Exhibits, contains “forward-looking statements” within the meaning of the USUnited States federal securities laws. All statements other than statements of historical facts included or incorporated by reference in in this report, including, without limitation, statements regarding our future financial position, business strategy, projected ~~costs~~ costs and plans and objectives of management for future operations, are forward-looking statements. The words “may,” “believe,” “intend,” “will,” “anticipate,” “expect,” “estimate,” “project,” “future,” “plan,” “strategy,” “probable,” “possible,” or “continue,” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters, often identify forward-looking statements. For these statements, Deep Well claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The forward-looking statements in this Annual Report include, among others, statements with respect to:

●

our current business strategy;

●

our future financial position and projected costs;

●

our projected sources and uses of cash;

●

our plan for future development and operations, including the building of all-weather roads;

●

our drilling and testing plans;

●

our proposed plans for further thermal in-situ development or demonstration project or projects;

●

the sufficiency of our capital in order to execute our business plan;

●

our reserves and resources estimates;

● the timing and sources of our future funding.;

●

the quantity and value of our reserves;

●

the intent to issue a distribution to our shareholders;

●

our or our operator’s objectives and plans for our current SAGD Project;

●

our plans for development of our Sawn Lake properties;

●

production levels from our current SAGD Project;

●

costs of our current SAGD Project;

● funding from the Farmee to pay our costs for the current SAGD ~~project~~Project in connection with the Farmout Agreement;

2017

●

additional sources of funding from the Farmout Agreement;

●

funding from the Farmee to cover our monthly operating expenses;

●

our access and availability to third-party infrastructure;

● present and future production of our properties; ~~and~~

●

our ability to extend our remaining lease past its primary expiration date; and

●

expectations regarding the ability of our Company and its subsidiaries to raise capital and to continually add to reserves through acquisitions and development.

These forward-looking statements are based on the beliefs and expectations of our management and are subject to significant risks and uncertainties. If underlying assumptions prove inaccurate or unknown risks or uncertainties materialize, actual results may differ materially from current expectations and projections. Factors that could cause actual results to differ materially from those set forward in the forward-looking statements include, but are not limited to:

●

changes in general business or economic conditions;

● changes in governmental legislation or regulation that affect our business; ● our ability to obtain necessary regulatory approvals and permits for the development of our properties, including obtaining the required water licences from Alberta Environment to withdraw water for our thermal operations;

●

our ability to obtain necessary regulatory approvals and permits for the development of our properties, including obtaining the required water licenses from Alberta Environment to withdraw water for our thermal operations;

●

changes to the greenhouse gas reduction program and other environmental and climate change regulations which are adopted by provincial or federal governments of Canada or which are being considered, which may also include cap and trade regimes, carbon taxes, increased efficiency standards, each of which could increase compliance costs and impose significant penalties for non-compliance;

●

increase in taxes and changes to existing legislation affecting governmental royalties or other governmental initiatives;

●

future marketing and transportation of our produced bitumen;

●

our ability to receive approvals from the AER for additional tests to further evaluate the wells on our lands;

●

our Farmout Agreement and joint operating agreements;

●

opposition to our regulatory requests by various third parties;

●

actions of aboriginals, environmental activists and other industrial disturbances;

●

the costs of environmental reclamation of our lands;

●

availability of labor or materials or increases in their costs;

●

the availability of sufficient capital to finance our business or development plans on terms satisfactory to us;

●

adverse weather conditions and natural disasters affecting access to our properties and well sites;

●

risks associated with increased insurance costs or unavailability of adequate coverage;

●

volatility in market prices for oil, bitumen, natural gas, diluent and natural gas liquids. A decline in oil prices could result in a downward revision of our future reserves and a ceiling test write-down of the carrying value of our oil sands properties, which could be substantial and could negatively impact our future net income and stockholders’ equity;

●

competition;

●

changes in labor, equipment and capital costs;

●

future acquisitions or strategic partnerships;

●

the risks and costs inherent in litigation;

●

imprecision in estimates of reserves, resources and recoverable quantities of oil, bitumen and natural gas;

●

product supply and demand;

●

changes and amendments in the Canadian Oil and Gas Evaluation Handbook and or the Petroleum Resources Management System to general disclosure of reserves and resources standards and specific annual reserves and resources disclosure requirements for reporting issuers with oil and gas activities;

●

future appraisal of potential bitumen, oil and gas properties may involve unprofitable efforts;

● the ability to meet minimum level of requirements and obtain approval from Alberta Energy to continue our oil sands leases beyond their expiry dates;

●

the ability to pay future escalating oil sands lease rents on our continued leases;

●

changes in general business or economic conditions;

●

risks associated with the finding, determination, evaluation, assessment and measurement of bitumen, oil and gas deposits or reserves;

●

geological, technical, drilling and processing problems;

●

third party performance of obligations under contractual arrangements;

● failure to obtain industry partner and other third -party consents and approvals, when required;

●

treatment under governmental regulatory regimes and tax laws;

●

royalties payable in respect of bitumen, oil and gas production;

●

unanticipated operating events which can reduce production or cause production to be shut-in or delayed;

●

incorrect assessments of the value of acquisitions, and exploration and development programs;

●

stock market volatility and market valuation of the common shares of our Company;

●

fluctuations in currency and interest rates; and

●

the additional risks and uncertainties, many of which are beyond our control, referred to elsewhere in this Annual Report and in our other SEC filings.

The preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description of risks and uncertainties, see the sections ~~elsewhere in this Annual Report~~ entitled “Risk Factors” and “Environmental Laws and Regulations” as disclosed in this annual report on Form 10-K for the fiscal year ended September 30, 2019 filed with the United States Securities and Exchange Commission (“SEC”) and the Alberta Securities Commission (“ASC”) on SEDAR. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated or expected. Any forward-looking statement speaks only as of the date on which it was made and, except as required by law, we disclaim any obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. However, any further disclosures made on related subjects in subsequent reports on Forms 10-K, 10-Q, 8-K and any other SEC filing or amendments thereto should be consulted.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a smaller reporting company as defined by Rule 12b-2 under the Exchange Act and therefore are not required to provide the information required under this item.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Deep Well Oil & Gas, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Deep Well Oil & Gas, Inc. (the “Company”) as of September 30, ~~2018~~2019 and ~~2017~~2018, and the related consolidated statements of operations ~~and comprehensive income (loss)~~, shareholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of September 30, ~~2018~~ 2019 and ~~2017~~2018, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Turner, Stone & Company, L.L.P.

Dallas, Texas

~~December~~January 2113, ~~2018~~2020

We have served as the Company’s auditor since 2015.

~~F-1~~20

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

Consolidated Balance Sheets

September 30, ~~2018~~2019 and September 30, ~~2017~~ 2018

	September 30,			September 30,
	2018			2017
	2019			2018
ASSETS
Current Assets
Cash and cash equivalents	$	~~298~~49,~~241~~715		$	1298,~~097,651~~241
Accounts receivable		4083,~~920~~398			8140,~~292~~920
Prepaid expenses		2434,~~730~~266			3624,~~076~~730
Total Current Assets		~~363~~167,~~891~~379			1363,~~215,019~~891
Long-term investments		~~398~~396,~~055~~782			~~407~~398,~~025~~055
Oil and gas properties, net, based on full cost method of accounting		2122,~~975~~040,~~868~~307			21,~~295~~975,~~674~~868
Property and equipment, net		8973,~~518~~509			~~115~~89,~~520~~518
TOTAL ASSETS	$	22,~~827~~677,~~332~~977		$	2322,~~033~~827,~~238~~332
LIABILITIES
Current Liabilities
Accounts payable and accrued liabilities	$	4569,~~137~~617		$	~~156~~45,~~218~~137
Accounts payable and accrued liabilities – related parties		–1,375			~~9,934~~–
Total Current Liabilities		4570,~~137~~992			~~166~~45,~~152~~137
Asset retirement obligations (Note 10)		~~493~~500,~~467~~392			493,~~411~~467
TOTAL LIABILITIES		~~538~~571,~~604~~384			~~659~~538,~~563~~604
(Commitments and contingencies Note 15)
SHAREHOLDERS’ EQUITY
Common Stock: (Note 11)
Authorized: 600,000,000 shares at $0.001 par value
Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 230,574,603 shares (September 30, 2018 – 230,574,603 shares)		230,574			230,574
Issued and outstanding: 230,574,603 shares
Additional paid in capital		43,104,276			43,104,276
(September 30, 2017 – 229,374,605 shares)		230,574			229,374
Subscriptions receivable – related party		–			(15,000	)
Additional paid in capital		43,104,276			42,845,292
Accumulated deficit		(21,228,257	)		(21,031,122	)
Subscriptions receivable – related party		(15,000	)		–
Total Shareholders’ Equity		22,106,593			22,288,728
Accumulated deficit		(21,031,122	)		(20,700,991	)
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	22,677,977		$	22,827,332
Total Shareholders’ Equity		22,288,728			22,373,675
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	22,827,332		$	23,033,238

See accompanying notes to the consolidated financial statements

~~F-2~~21

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

Consolidated Statements of Operations ~~and Comprehensive Income (Loss)~~

For the Years Ended September 30, ~~2018~~ 2019 and ~~2017~~2018

	September 30,			September 30,
	2018			2017
	2019			2018
Revenue	$	–		$	–
Royalty refunds (expenses)		–			–
Revenue, net of royalty		–			–
Expenses
Operating expenses		~~148~~97,~~046~~643			~~142~~148,~~169~~046
Operating expense covered by Farmout		(~~148~~97,~~046~~643	)		(~~142~~148,~~169~~046	)
General and administrative		~~289~~165,~~209~~405			~~222~~289,~~252~~209
Depreciation, accretion and depletion		5646,~~032~~036			7656,~~938~~032
Net loss from operations		(~~345~~211,~~241~~441	)		(~~299~~345,~~190~~241	)
Other income and expenses
Rental and other income		96,~~054~~612			29,~~575~~054
Interest income		67,~~056~~694			36,~~517~~056
Net loss and comprehensive loss	$	(330,131	)	$	(293,098	)
Net loss	$	(197,135	)	$	(330,131	)
Net loss per common share
Basic and Diluted	$	(0.000009	)	$	(0.000014	)
Weighted Average Outstanding Shares (in thousands)
Basic and Diluted		~~229~~230,~~735~~574			229,~~374~~735

See accompanying notes to the consolidated financial statements

~~F-3~~22

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

Consolidated Statements of Shareholders’ Equity

For the Years Ended September 30, ~~2018~~ 2019 and ~~2017~~2018

	Common Shares
					Additional
	Common Shares				Paid in		Subscription			Accumulated
					Paid in		Subscription			Accumulated
	Shares		Amount		Capital		Receivable			Deficit			Total
Balance at September 30, 2016		229,374,605	$	229,374	$	42,842,978	$	–		$	(20,407,893	)	$	22,664,459
Warrants Expired November 23, 2016 - 52,155,221 warrants (Note 11)		–		–		–		–			–			–
Options granted for services		–		–		2,314		–			–			2,314
Net operating loss for the year ended September 30, 2017		–		–		–		–			(293,098	)		(293,098	)
Balance at September 30, 2017		229,374,605	$	229,374	$	42,845,292	$	–		$	(20,700,991	)	$	22,373,675
Options exercised, June 2018		1,199,998		1,200		13,800		–		$	–			15,000
Subscription receivable		–		–		–		(15,000	)					(15,000	)
Distribution refund		–		–		245,184		–			–			245,184
Net operating loss for the year ended September 30, 2018		–		–		–		–			(330,131	)		(330,131	)
Net Loss for the year ended September 30, 2018		–		–		–		–			(330,131	)		(330,131	)
Balance at September 30, 2018		230,574,603	$	230,574	$	43,104,276	$	(15,000	)	$	(21,031,122	)	$	22,288,728
Subscription receivable collected		–		–		–		15,000			–			15,000
Net Loss for the year ended September 30, 2019		–		–		–		–			(197,135	)		(197,135	)
Balance at September 30, 2019		230,574,603	$	230,574	$	43,104,276	$	–		$	(21,228,257	)	$	22,106,593

See accompanying notes to the consolidated financial statements

~~F-4~~23

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

Consolidated Statements of Cash Flows

For the Years Ended September 30, ~~2018~~ 2019 and ~~2017~~2018

	September 30,			September 30,
	2018			2017
	2019			2018
Operating Activities
Net loss	$	(~~330~~197,~~131~~135	)	$	(~~293~~330,~~098~~131	)
Items not affecting cash:
Share-based compensation		–			2,314
Depreciation, accretion and depletion		46,036			56,032
Depreciation, accretion and depletion		56,032			76,938
Net changes in non-cash working capital (Note 13)		(26,159	)		(69,297	)
Net changes in non-cash working capital (Note 13)		(69,297	)		54,337
Net Cash Used in Operating Activities		(177,258	)		(343,396	)
Net Cash Used in Operating Activities		(343,396	)		(159,509	)
Investing Activities
Purchase of equipment		(~~940~~882	)		(~~2,552~~940	)
Investment in oil and gas properties		(~~705~~93,~~917~~078	)		(~~144~~705,~~383~~917	)
Long-term investments		57,~~659~~692			35,~~173~~659
Net Cash Used in Investing Activities		(~~701~~86,~~198~~268	)		(~~143~~701,~~762~~198	)
Financing Activities
Distribution refund		245,184			–
Subscription receivable collected		15,000			–
Net Cash Provided by Financing Activities		245,184			–
Distribution refund		–			245,184
Decrease in cash and cash equivalents		(799,410	)		(303,271	)
Net Cash Provided by Financing Activities		15,000			245,184
Cash and cash equivalents, beginning of year		1,097,651			1,400,922
Decrease in cash and cash equivalents		(248,526	)		(799,410	)
Cash and cash equivalents, end of year	$	298,241		$	1,097,651
Cash and cash equivalents, beginning of year		298,241			1,097,651
Cash and cash equivalents, end of year	$	49,715		$	298,241
Supplemental Cash Flow Information:
Cash paid for interest	$	–		$	–
Cash paid for income taxes	$	–		$	–

See accompanying notes to the consolidated financial statements

~~F-5~~24

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

Notes to the Consolidated Financial Statements

September 30, 2019 ~~2018~~ and ~~2017~~2018

1.	NATURE OF BUSINESS AND BASIS OF PRESENTATION

Nature of Business

Deep Well Oil & Gas, Inc. was originally incorporated on July 18, 1988 under the laws of the state of Nevada as Worldwide Stock Transfer, Inc. (Worldwide Stock Transfer, Inc. later changed its name to Allied Devices Corporation) and in connection with a plan of reorganization, effective on September 10, 2003, the company was reorganized and changed its name to Deep Well Oil & Gas, Inc. (“Deep Well”).

Deep Well together with its subsidiaries, Northern Alberta Oil Ltd. and Deep Well Oil & Gas (Alberta) Ltd, (collectively referred to as the “Company”) is an independent junior oil sands exploration and development company with an existing oil sands land base in the Peace River oil sands area in Alberta, Canada.

These consolidated financial statements have been prepared showing the name “Deep Well Oil & Gas, Inc. (and Subsidiaries)” (“the Company”) and the post-split common stock, with $0.001 par value.

Basis of Presentation

These consolidated financial statements are expressed in U.S. dollars and are prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

These statements reflect all adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the opinion of management, are necessary for a fair presentation of the information contained herein.

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

These consolidated financial statements include the accounts of two wholly owned subsidiaries: (1) Northern Alberta Oil Ltd. (“Northern”) from the date of acquisition, being June 7, 2005, incorporated under the Business Corporations Act (Alberta), Canada; and (2) Deep Well Oil & Gas (Alberta) Ltd., incorporated under the Business Corporations Act (Alberta), Canada on September 15, 2005. All inter-company balances and transactions have been eliminated.

Cash and Cash Equivalents

The Company considers all highly liquid instruments with a maturity of three months or less at the time of issuance to be cash equivalents.

Allowance for Doubtful Accounts

The Company determines allowances for doubtful accounts based on aging of specific accounts. Accounts receivable are stated at the historical carrying amounts net of allowances for doubtful accounts and include only the amounts the Company deems to be collectable. The allowance for bad debts was $nil and $nil at September 30, ~~2018~~2019 and September 30, ~~2017~~2018, respectively.

Crude oil and natural gas properties

The Company follows the full cost method of accounting for oil sands properties pursuant to SEC Regulation S-X Rule 4-10. The full cost method of accounting for oil and gas operations requires that all costs associated with the exploration for and development of oil and gas reserves be capitalized on a country by country basis. Such costs include lease acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.

FUnder the full cost method, oil and gas properties are subject to the ceiling test performed quarterly. A ceiling test write-6down is recognized in net earnings if the carrying amount of a cost centre exceeds the "cost centre ceiling". The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not being amortized, and (C) the lower of cost or fair value of unproved properties included in the costs being amortized; less (D) related income tax effects. During the 2019 fiscal year, no ceiling test write-downs were recorded for the Company’s oil and gas properties.

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 2018 fiscal year, no ceiling test write-downs were recorded for our oil and gas properties.25

Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed annually for impairment. Costs that have been impaired are included in the costs subject to depletion within the full cost pool.

Property and Equipment

Property and equipment are stated at cost less accumulated depreciation. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. Only half of the depreciation rate is taken in the year of acquisition. The following is a summary of the depreciation rates used in computing depreciation expense:

	%
Software		100
Computer equipment		55
Portable work camp		30
Vehicles		30
Road Mats		30
Wellhead		25
Office furniture and equipment		20
Oilfield Equipment		20
Tanks		10

Expenditures for major repairs and renewals that extend the useful life of the asset are capitalized. Minor repair expenditures are charged to expense as incurred. Leasehold improvements are amortized over the greater of five years or the remaining life of the lease agreement.

Depreciation, Depletion and Amortization - Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.

Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred. Since there was no production in the last two fiscal years no depletion has been booked in either year.

Asset Retirement Obligations

The Company accounts for asset retirement obligations by recording the fair value of the estimated future cost of the Company’s plugging and abandonment obligations. The asset retirement obligation is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the fair value of the liability can reasonably be estimated. Upon initial recognition of an asset retirement obligation, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in their present value through charges to oil and gas production and well operations costs. The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion, and amortization. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.

Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs, and changes in the estimated timing of settling asset retirement obligations. As of September 30, ~~2018~~2019, and ~~2017~~2018, asset retirement obligations amount to $~~493~~500,~~467~~392 and $493,~~411~~467, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.

Foreign Currency Translation

The functional currency of ~~the~~ ~~Canadian~~the ~~subsidiaries~~Company is the ~~United~~US ~~States~~ dollar~~. However~~, but the functional currency of the Company’s Canadian subsidiaries ~~transact~~is inthe Canadian ~~dollars~~ dollar. Consequently, monetary assets and liabilities are remeasured into United States dollars at the exchange rate on the balance sheet date and non-monetary items are remeasured at the rate of exchange in effect when the assets are acquired, or obligations incurred. Revenues and expenses are remeasured at the average exchange rate prevailing during the period. Foreign currency transaction gains and losses have not been material and therefore are included in results of operations and not separately reported as a component of comprehensive income.

~~F-7~~26

Accounting Method

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

Dividend Policy

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

Financial, Concentration and Credit Risk

The Company’s consideration or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit insurance limit. As of the ~~2018~~2019 fiscal year end, the Company has approximately $~~199~~3,~~988~~470 funds that are in excess of deposit insurance limits, which may have financial credit risk. For the Company funds that are maintained in a financial institution which has its deposits fully guaranteed by CUDGC, there is no financial credit risk.

The Company is not directly subject to credit risk resulting from the concentration of its crude oil sales. For the year ended September 30, ~~2018~~2019 and September 30, ~~2017~~2018, the Company recorded no oil sales.

Income Taxes

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

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

Revenue Recognition

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

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

Advertising and Market Development

The Company expenses advertising and market development costs as incurred.

Basic and Diluted Net Loss Per Share

Basic net loss per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net loss per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were 8600,~~080,~~000 potentially dilutive securities excluded from the the diluted earnings per share calculation ~~because~~ 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.

~~F-8~~27

Environmental Requirements

The Company is subject to federal, provincial and local environmental laws and regulations. These laws generally provide for control of pollutants released into the environment and protection of the environment. Under these laws and regulations, the Company could be liable for clean-up costs, other environmental damages and fines or penalties related to the Company’s oilsands operations. When the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated environmental remediation liabilities are recorded. At the report date, environmental requirements related to the oil properties acquired are unknown and therefore an estimate of any future cost cannot be made.

Share-Based Compensation

The Company accounts for stock options granted to directors, officers, employees and non-employees using the fair value method of accounting. The fair value of stock options for directors, officers, employees and their corporate entities are calculated at the date of grant and are expensed over the vesting period of the options on a straight-line basis. For non-employees, the fair value of the options is measured on the earlier of the date at which the counterparty performance is complete or the date at which the performance commitment is reached. The Company uses the Black-Scholes model to calculate the fair value of stock options issued, which requires certain assumptions to be made at the time the options are awarded, including the expected life of the option, the expected number of granted options that will vest and the expected future volatility of the stock. The Company reflects estimates of award forfeitures at the time of grant and revises in subsequent periods, if necessary, when forfeiture rates are expected to change.

Recently Adopted Accounting Standards

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. This ASU does not apply to the Company’s oil sand leases. It may affect the equipment leases. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

Accounting Standard Update No. 2014-09, (“ASU 2014-09”) Revenue from Customers (Topic 606), became effective for us in the period ending September 30, 2018. No significant adjustment was required as a result of adopting the new revenue standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is expected to be immaterial to the Company’s net income on an ongoing basis.

Estimates and Assumptions

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

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

3.	OIL AND GAS PROPERTIES

The Company’s oil sands acreage as of September 30, ~~2018~~2019, covers 3719,~~322~~610 gross acres (2913,~~383~~442 net acres) of land under ~~nine~~seven oil sands leases. ~~Until~~The ~~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:

~~(i)~~1. OfOut ~~the~~of ~~Company’s acreage,~~ 20,242 gross acres (13,284 net acres) under five oil sands leases that were set to expiry on July 10, 2018, 14,549 gross acres (8,571 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. In November of 2017, the Company’s joint venture partner and operator of two of ~~these~~the five oil sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591 gross acres (1,898 net acres) and onin January ~~29,~~ 2018, approval was received from Alberta Energy to continue 6,958 gross acres (1,740 net acres). In June of 2018, the Company as operator of three of these five oil sands leases, submitted three continuation applications to the Alberta Oil Sands Tenure division to apply to continue another 7,591 gross acres (6,832 net acres) where resources were identified and onin July ~~15,~~ 2018 and April 2019, approval was received from Alberta Energy to continue 57,~~693~~591 gross acres (56,~~124~~832 net acres). ~~The~~Of ~~Company~~these ~~has~~five ~~not~~oil ~~yet~~sands ~~received~~leases ~~approval~~that onwere ~~one~~set ~~continuation application it submitted in June of 2018~~ to ~~continue~~expiry ~~another~~on ~~1,898~~July ~~gross acres (1~~10,~~708~~ ~~net acres). As of September 30,~~ 2018, a total of 5,693 gross acres (4,713 net acres) ~~on five oil sands leases~~ expired without being continued. These expired lands were primarily areas where the Company determined that there was ~~unable~~no toor ~~ascertain~~limited exploitable resources. ~~Continued~~These continued leases ~~have~~are nonow ~~future~~held ~~expiry~~by ~~dates~~the ~~but~~Company ~~are~~for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases.;

~~F-9~~28

~~(ii)~~2. ~~Of the Company’s acreage,~~ 19,610 gross acres (17,649 net acres) under the three most northern oil sands leases ~~are~~were set to expire on August 19, 2019. ~~The~~In August 2019, the Company ~~intends~~submitted one continuation application to the Alberta Oil Sands Tenure division to apply ~~for~~to acontinue ~~term~~1,898 ~~extension~~acres on(1,708 ~~these~~net ~~three~~acres) ~~northern~~of ~~oil~~the ~~sands~~19,610 ~~leases~~gross acres (17,649 ~~however~~net itacres) ison ~~not~~one ~~certain~~of ifthe annorthern ~~extension~~most ~~will~~leases beand ~~granted~~subsequently byin early October 2019 approval was received from Alberta Energy to continue 1,898 gross acres (1,708 net acres) past the expiry date of the lease. On August 19, 2019, 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where the Company determined that there was no or limited exploitable resources; and

~~(iii)~~3. ~~Of the Company’s acreage,~~ 3,163 gross acres (3,163 net acres) under one oil sands lease are set to expire on April 9, 2024. It is the Company’s opinion that ~~the~~they ~~Company~~have ~~has~~ already met the governmental requirements for this lease, and itthey will be applying to continue this lease ~~beyond~~into ~~its expiry date~~perpetuity.

Lease Rental Commitments

The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The lease terms include certain commitments related to oil sands properties that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta continued oil sands leases past their expiry dates are subject to escalating rental payments in respect of each term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease. Escalating rent is payable at the end of each term year, while annual rent for leases are due at the beginning of each term year. Lessees of continued oil sands leases may reduce or eliminate their escalating rent obligations by conducting exploration or development work, or research, on the non-producing lease. As of September 30, ~~2018~~2019, excluding any eligible research, exploration and or development costs that may be used to reduce the Company’s yearly escalating future rents, the following table sets out the estimated net payments due under this commitment, which could be as high as:

		(USD $)	~~(USD $)~~		(Cdn $)	~~(Cdn $)~~
	2019		$	20,874		$	27,022
2020		$	23,796		$	31,514
	2020		$	20,874		$	27,022
2021		$	22,782		$	30,170
	2021		$	19,836		$	25,678
2022		$	29,623		$	39,230
	2022		$	26,835		$	34,738
2023		$	31,188		$	41,303
	2023		$	23,632		$	30,592
2024		$	26,898		$	35,621
Subsequent	~~Subsequent~~	$	$144,465	~~127,505~~	$	$191,318	~~165,058~~

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:

1) The original requirement was to drill evaluation wells on each section within the lease, however the Alberta Department of Energy has temporarily relaxed the drilling requirements under section 3(2)(a) of the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta whereby the drilling requirement is now to drill one evaluation well per three sections; or

2) drill evaluation wells on at least 60% of the sections within the lease of which 25% of the evaluation wells must be cored, and acquire and process two miles of seismic data for the remaining undrilled sections within the lease.

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~~Estimates ~~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~~period ended September 30, ~~2018~~2019.

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

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

Farmout Agreement

On July 31, 2013, the Company entered into a Farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund the Company’s share of the Alberta Energy Regulator (“AER”) approved joint Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”) at the Company’s Sawn Lake heavy oil reservoir in North Central Alberta, Canada. In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for the ~~Company~~Farmee’s ~~portion~~share and the Company’s share of the capital costs and operating expenses for the SAGD Project, in return for a net 25% working interest in 12 sections (now 11 sections) where the Company had a working interest of 50% (before the execution of the Farmout Agreement). The Farmee will also provide funding to cover monthly operating expenses of the Company, of which the first such monthly payment began in respect of the month of August 2013 and shall not to exceed $30,000 per month.

~~F-10~~29

4.	CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES

The following table illustrates capitalized costs relating to oil producing activities for the year ended September 30, ~~2018~~2019 and September 30, ~~2017~~2018:

			September 30, 2018				September 30, 2017
		September 30, 2019				September 30, 2018
Unproved Oil and Gas Properties	~~Unproved Oil and Gas Properties~~	$	$22,147,367	~~22,071,787~~		$	$22,071,787	~~21,380,452~~
Accumulated Depreciation and Depletion	~~Accumulated Depreciation and Depletion~~		(107,060	~~(95,919~~)	)		(95,919	~~(84,778~~)	)
Net Capitalized Cost	~~Net Capitalized Cost~~	$	$22,040,307	~~21,975,868~~		$	$21,975,868	~~21,295,674~~

Depreciation and depletion expenses for the years ended September 30, ~~2018~~2019 and ~~2017~~2018 were $11,141 and $11,141 respectively.

5.	EXPLORATION ACTIVITIES

The following table presents ~~information~~ information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the years ended September 30, ~~2018~~2019 and September 30, ~~2017~~2018:

			September 30, 2018			September 30, 2017
		September 30, 2019			September 30, 2018
Acquisition of Properties:	~~Acquisition of Properties:~~
Proved	~~Proved~~	$	$–	–	$	$–	–
Unproved	~~Unproved~~	$	–	~~38,185~~	$	38,185	~~142,400~~
Exploration costs	~~Exploration costs~~	$	75,580	~~710,012~~	$	710,012	–
Development costs	~~Development costs~~	$	–	–	$	–	–

6.	INVESTMENT IN EQUITY SECURITIES

On February 25, 2005, the Company acquired an interest in Signet Energy Inc. (“Signet” formerly Surge Global Energy, Inc.) as a result of a Farmout Agreement dated February 25, 2005. Signet amalgamated with Andora Energy Corporation (“Andora”) in 2007.

As of November 19, 2008, the ~~Company~~ Company converted its Signet shares into 2,241,558 shares of Andora, which presently represents an equity interest in Andora of ~~approximately~~ approximately 2.24% as of ~~December~~March 31, ~~2017~~2019, which is Andora’s ~~fiscal~~first ~~year~~quarter end. These shares are carried at a nominal value using the cost method and their value is included under oil and gas properties on the Company’s balance sheet.

F-11

7.	PROPERTY AND EQUIPMENT

September 30, 2018

September 30, 2019

Accumulated

~~Accumulated~~

Net Book

~~Net Book~~

Cost

~~Cost~~

Depreciation

~~Depreciation~~

Value

~~Value~~

Computer equipment

~~Computer equipment~~

$36,569

~~35,689~~

$35,177

~~34,175~~

1,392

~~1,514~~

Office furniture and equipment

~~Office furniture and equipment~~

34,130

~~34,130~~

31,826

~~31,249~~

2,304

~~2,881~~

Software

~~Software~~

5,826

~~5,826~~

5,826

~~5,826~~

–

Leasehold improvements

~~Leasehold improvements~~

4,936

~~4,936~~

4,936

~~4,936~~

–

Portable work camp

~~Portable work camp~~

170,580

~~170,580~~

166,578

~~164,862~~

4,002

~~5,718~~

Vehicles

~~Vehicles~~

38,077

~~38,077~~

38,077

~~38,077~~

–

Oilfield equipment

~~Oilfield equipment~~

249,046

~~249,046~~

223,818

~~217,511~~

25,228

~~31,534~~

Road mats

~~Road mats~~

364,614

~~364,614~~

355,859

~~352,108~~

8,755

~~12,506~~

Wellhead

~~Wellhead~~

3,254

~~3,254~~

3,254

~~3,254~~

–

Tanks

~~Tanks~~

96,085

~~96,085~~

64,257

~~60,721~~

31,828

~~35,364~~

$1,003,117

~~1,002,237~~

$929,608

~~912,720~~

73,509

~~89,518~~

	September 30, 2017
			Accumulated		Net Book
	Cost		Depreciation		Value
Computer equipment	$	34,750	$	32,899	$	1,851
Office furniture and equipment		34,130		30,529		3,601
Software		5,826		5,826		–
Leasehold improvements		4,936		4,936		–
Portable work camp		170,580		162,305		8,275
Vehicles		38,077		38,077		–
Oilfield equipment		249,045		204,917		44,128
Road mats		364,614		346,748		17,866
Wellhead		3,254		2,747		507
Tanks		96,085		56,793		39,292
	$	1,001,297	$	885,777	$	115,520

There was $26,942 of depreciation expense for the year ended September 30, 2018 (September 30, 2017 - $48,887).

	September 30, 2018
			Accumulated		Net Book
	Cost		Depreciation		Value
Computer equipment	$	35,689	$	34,175	$	1,514
Office furniture and equipment		34,130		31,249		2,881
Software		5,826		5,826		–
Leasehold improvements		4,936		4,936		–
Portable work camp		170,580		164,862		5,718
Vehicles		38,077		38,077		–
Oilfield equipment		249,046		217,511		31,534
Road mats		364,614		352,108		12,506
Wellhead		3,254		3,254		–
Tanks		96,085		60,721		35,364
	$	1,002,237	$	912,720	$	89,518

There was $16,889 of depreciation expense for the year ended September 30, 2019 (September 30, 2018 - $26,942).

8.	LONG-TERM INVESTMENTS

Our Long-term investments ~~consist~~ consist of cash held in trust byon behalf of our potential obligations with the AER. ~~which~~These ~~bears~~cash ~~interest~~investments atearn aan interest rate of prime minus 0.375% and ~~has~~mature noonce ~~stated~~our ~~date~~obligations ofto ~~maturity~~the AER are satisfied. These investments are required by the AER to ensure that there are sufficient future cash ~~flows~~reserves to meet the expected future asset retirement obligations for abandonment and reclamation of the Company’s wells and wellsites and are restricted for this purpose.

9.	SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES

Accounts payable – related parties were $~~Nil~~1,375 as of September 30, ~~2018~~2019 (September 30, ~~2017~~2018 - $~~9,934~~Nil) for expenses to be reimbursed to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.

Subscriptions receivable – related parties was $~~15,000~~ Nil as of September 30, ~~2018~~2019 (September 30, ~~2017~~2018 - $~~Nil~~15,000) for the amount owed to the Company from one director for the exercise of his stock options. ~~This amount was subsequently paid to the Company.~~

As of September 30, ~~2018~~2019, officers, directors, their families, and their controlled entities have acquired 53.96% of the Company’s outstanding common capital stock. This percentage does not include unexercised stock options.

The Company incurred expenses $~~140~~135,~~274~~666 to one related party, Concorde Consulting, an entity controlled by a director, for professional fees and consulting services provided to the Company during the year ended September 30, ~~2018~~2019 (September 30, ~~2017~~2018 - $~~136~~140,~~980~~274). These amounts were fully paid as of September 30, ~~2018~~2019.

F-12

10.

ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the ~~Alberta~~AER ~~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, ~~2018~~2019, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $~~624~~610,~~354~~291 (September 30, ~~2017~~2018 - $~~647~~624,~~631~~354). The fair value of the liability at September 30, ~~2018~~2019 is estimated to be $~~493~~500,~~467~~392 (September 30, ~~2017~~2018 - $493,~~411~~467) using a risk free rate of 3.74% and an inflation rate of 2%. The actual costs to settle the obligation are expected to occur in approximately 2524 years.

Changes to the asset retirement obligation were as follows:

			September 30, 2018				September 30, 2017
		September 30, 2019				September 30, 2018
Balance, beginning of period	~~Balance, beginning of period~~	$	$493,467	~~493,411~~		$	$493,411	~~452,533~~
Liabilities incurred	~~Liabilities incurred~~		–	–			–	–
Effect of foreign exchange	~~Effect of foreign exchange~~		(11,081	~~(17,893~~)	)		(17,893	~~23,969~~)
Disposal	~~Disposal~~		–	–			–	–
Accretion expense	~~Accretion expense~~		18,006	~~17,949~~			17,949	~~16,909~~
Balance, end of period	~~Balance, end of period~~	$	$500,392	~~493,467~~		$	$493,467	~~493,411~~

11.

COMMON STOCK

As of September 30, ~~2018~~2019, the Company had outstanding 230,574,603 shares of common stock.

Return of Capital Distribution

On August 9, 2013, the Company approved a distribution to its shareholders in the amount of $0.07 per share to be payable on September 20, 2013 to the holders of record of all the issued and outstanding shares of common stock of the Company as of the close of business on August 16, 2013. This cash distribution to the Company’s shareholders was not a dividend paid out of the earnings and profits, but was a non-dividend distribution characterized as a “return of capital”. On June 20, 2018, $245,184 was returned to the Company.

Warrants

OnThere ~~June~~were ~~20,~~no ~~2016,~~ warrants tooutstanding ~~acquire~~as upof toSeptember ~~520~~30,~~000~~ ~~common~~2019 ~~shares~~(September ~~of the Company~~30, ~~expired~~2018 ~~unexercised~~– Nil).

On November 23, 2016, warrants to acquire up to 52,155,221 common shares of the Company, expired unexercised.

There were no warrants outstanding as of September 30, 2018 (September 30, 2017 – Nil).

12.

STOCK OPTIONS

On November 28, 2005, and as amended on December 4, 2013, the Board of Deep Well adopted the Deep Well Oil & Gas, Inc. Stock Option Plan (the “Plan’). The Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Plan, is administered by the Board, permits options to acquire shares of the Company’s common stock (the “Common Shares”) to be granted to directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons providing services to the Company or its subsidiaries.

The maximum number of shares, which may be reserved for issuance under the Plan, may not exceed 10% of the Company’s issued and outstanding Common Shares, subject to adjustment as contemplated by the Plan. The aggregate number of Common Shares with respect to which options may be vested to any one person (together with their associates) under the plan, together with all other incentive plans of the Company in any one year shall not exceed 2% of the total number of Common Shares outstanding, and in total may not exceed 6% of the total number of Common Shares outstanding.

OnBetween ~~March~~June 238 to 10, ~~2016~~2018, ~~900~~five directors, two contractors and one employee of the Company, exercised a total of 3,150,000 ~~stock~~option shares at an exercise price of ~~options~~$0.05 ~~previously~~by ~~granted~~way of a cashless exercise to acquire a total of 899,998 common shares of the Company, based upon the market value of the Company’s common stock of $0.07 per share on ~~March~~June 238, ~~2011~~2018, whereby 2,250,002 common shares were withheld by the Company to ~~two~~pay ~~directors,~~for ~~expired~~the ~~unexercised~~exercise price of the options. The stock certificates from the latest exercise of stock options are currently held in escrow upon final approval and release by Management of the Company.

Between June 8 to 10, 2018, five directors, two contractors and one employee of the Company, exercised a total of 3,150,000 option shares at an exercise price of $0.05 by way of a cashless exercise to acquire a total of 899,998 common shares of the Company, based upon the market value of the Company’s common stock of $0.07 per share on June 8, 2018, whereby 2,250,002 common shares were withheld by the Company to pay for the exercise price of the options.

F-13

On June 19, 2018, one director of the Company acquired 300,000 common shares of the Company upon exercising stock options, at an exercise price of $0.05 per common share for total gross proceeds to the Company of $15,000.

~~For~~On ~~the~~October ~~year ended September 30~~28, 2018, ~~the Company recorded no share-based compensation expense related to~~ 250,000 stock options ~~(September~~previously ~~30,~~granted ~~2017~~on –October $228,~~314).~~ ~~As of~~2013 ~~September 30, 2018, there was no unrecognized compensation cost related~~ to ~~option~~a ~~awards.~~contractor ~~Compensation~~for ~~expense~~services isin ~~based~~connection ~~upon straight-line~~with ~~depreciation of~~ the ~~grant-date~~Farmout ~~fair~~Agreement, ~~value over the vesting period of the underlying unit option~~expired unexercised.

	Shares Underlying Options Outstanding						Shares Underlying Options Exercisable
Range of Exercise Prices	Shares Underlying Options Outstanding		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Shares Underlying Options Exercisable		Weighted Average Exercise Price
$0.30 at September 30, 2018		250,000		0.08		0.30		250,000		0.30
$0.34 at September 30, 2018		450,000		0.18		0.34		450,000		0.34
$0.38 at September 30, 2018		6,780,000		0.97		0.38		6,780,000		0.38
$0.23 at September 30, 2018		600,000		1.13		0.23		600,000		0.23
		8,080,000		0.91		0.36		8,080,000		0.36

On December 4, 2018, 450,000 stock options previously granted on December 4, 2013 to one director, expired unexercised.

~~The~~On ~~aggregate~~September ~~intrinsic~~19, ~~value~~2019, 6,780,000 ofstock ~~exercisable~~ options aspreviously ofgranted on September 3019, ~~2018~~2014 to seven directors, ~~was~~two ~~$Nil~~contractors ~~(September~~and ~~30,~~one ~~2017~~employee -expired ~~$Nil)~~unexercised.

~~The~~For ~~following~~the isyear aended ~~summary~~September 30, of2019, the Company recorded no share-based compensation expense related to stock ~~option~~options ~~activity~~(September 30, 2018 – $Nil). asAs atof September 30, ~~2018:~~2019, there was no unrecognized compensation cost related to option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.

			Number of Underlying Shares				Weighted Average Exercise Price			Weighted Average Fair Market Value
		Shares Underlying Options Outstanding										Shares Underlying Options Exercisable
	Balance, September 30, 2017			11,530,000			$	0.27		$	0.22
Range of Exercise Prices		Shares Underlying Options Outstanding				Weighted Average Remaining Contractual Life			Weighted Average Exercise Price			Shares Underlying Options Exercisable		Weighted Average Exercise Price
	Exercised, June 8, 2018			(3,450,000	)			0.05			0.04
$0.23 at September 30, 2019			600,000				0.13		$	0.23			600,000	$	0.23
	Balance, September 30, 2018			8,080,000				0.36			0.29
	Exercisable, September 30, 2018			8,080,000				0.36			0.29

~~A summary of the options granted at September 30, 2018 and 2017 and changes during the periods then ended is presented below:~~32

	September 30, 2018					September 30, 2017
	Shares			Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding balance at beginning of period		11,530,000		$	0.27		11,530,000	$	0.27
Vested - November 17, 2016							200,000		0.23
Exercised, June 8, 2018		(3,450,000	)		0.05
Outstanding at end of period		8,080,000		$	0.36		11,530,000	$	0.27
Exercisable		8,080,000		$	0.36		11,530,000	$	0.27

The aggregate intrinsic value of exercisable options as of September 30, 2019, was $Nil (September 30, 2018 - $Nil).

~~There~~The ~~were~~following nois ~~remaining~~a ~~unvested~~summary of stock ~~options~~option ~~outstanding~~activity as ofat September 30, ~~2018 (September 30, 2017 – Nil).~~2019:

	Number of Underlying Shares			Weighted Average Exercise Price		Weighted Average Fair Market Value

Balance, September 30, 2018		8,080,000		$	0.36	$	0.29

Expired, October 28, 2018		(250,000	)		0.30		0.30
Expired, December 4, 2018		(450,000	)		0.34		0.36
Expired, September 19, 2019		(6,780,000	)		0.38		0.30
Balance, September 30, 2019		600,000		$	0.23	$	0.18

Exercisable, September 30, 2019		600,000		$	0.23	$	0.18

A summary of stock options at September 30, 2019 and 2018 and changes during the periods then ended is presented below:

	September 30, 2019					September 30, 2018
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price

Outstanding balance at beginning of period		8,080,000		$	0.36		11,530,000		$	0.29

Exercised, June 8, 2018							(3,450,000	)		0.05
Expired, October 28, 2018		(250,000	)		0.30
Expired, December 4, 2018		(450,000	)		0.34
Expired, September 19, 2019		(6,780,000	)		0.38

Outstanding at end of period		600,000		$	0.23		8,080,000		$	0.36

Exercisable		600,000		$	0.23		8,080,000		$	0.36

There were no remaining unvested stock options outstanding as of September 30, 2019 (September 30, 2018 – Nil).

Measurement Uncertainty for Stock Options

The Company used the Black-Scholes pricing model (“Black-Scholes”) to value the stock options. This pricing model was developed for use in estimating the fair value of traded “European” options. The stock options that are granted to employees, directors and consultants are non-transferable and some vest over time, and are “American” options. This pricing model requires the input of subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes in the assumptions, and therefore can materially affect the calculated fair value of the stock options. The following assumptions were used in the Black-Scholes pricing model to value the stock options:

Expected Term – Expected term of 5 years represents the period that the Company’s stock-based awards are expected to be outstanding.

F-14

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%.

13.

CHANGES IN NON-CASH WORKING CAPITAL

		September 30,	~~September 30,~~			September 30,	~~September 30,~~
			2018				2017
		2019				2018
Accounts receivable	~~Accounts receivable~~	$	$(42,478	~~40,372~~)		$	$40,372	~~(58,715~~	)
Prepaid expenses	~~Prepaid expenses~~		(9,536	~~11,346~~)			11,346	~~(3,125~~	)
	Accounts payable and accounts payable and accrued liabilities - related party			(121,015	)			116,177
Accounts payable			25,855				(121,015	)
		$	$(26,159	~~(69,297~~)	)	$	$(69,297	~~54,337~~)

14.

INCOME TAXES

As of September 30, ~~2018~~2019, the Company has approximately $62,~~442~~190,~~069~~855 (~~2017~~2018 – $6,~~311~~442,~~751~~069) of operating losses expiring through ~~2038~~2039 that may be used to offset future taxable income but are subject to various limitations imposed by rules and regulations of the Internal Revenue Service. The net operating losses are limited each year to offset future taxable income, if any, due to the change of ownership in the Company's outstanding shares of common stock. In addition, at September 30, ~~2018~~2019, the Company had an unused Canadian net operating loss carry-forward of approximately $87,~~096~~865,~~433~~973 (~~2017~~2018 – $78,~~864~~096,~~432~~433), expiring through ~~2038~~2039. These operating loss carry-forwards may result in future income tax benefits of approximately $32,~~538~~269,~~871~~253. However, because realization is uncertain at this time, a valuation reserve in the same amount has been established. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The components of the net deferred tax asset, the statutory tax rate, the effective rate and the elected amount of the valuation allowance are as follows:

			Year Ended September 30, 2018				Year Ended September 30, 2017
		Year Ended September 30, 2019				Year Ended September 30, 2018
Statutory and effective tax rate	~~Statutory and effective tax rate~~
Domestic	~~Domestic~~
Statutory U.S. federal rate	~~Statutory U.S. federal rate~~		21	21%	%		21	21%	%
Foreign	~~Foreign~~		26.75	27%	%		27	27%	%

			Year Ended September 30, 2018				Year Ended September 30, 2017
		Year Ended September 30, 2019				Year Ended September 30, 2018
Income taxes recovered at the statutory and effective tax rate	~~Income taxes recovered at the statutory and effective tax rate~~
Domestic	~~Domestic~~
Statutory U.S. federal rate	~~Statutory U.S. federal rate~~	$	$24,637	~~28,484~~		$	$28,484	~~24,570~~
Foreign	~~Foreign~~		21,347	~~52,513~~			52,513	~~47,547~~
Timing differences:	~~Timing differences:~~
Non-deductible expenses	~~Non-deductible expenses~~		(12,534	~~(21,102~~)	)		(21,102	~~(14,266~~)	)
Other deductible charges	~~Other deductible charges~~							–
Benefit of tax losses not recognized in the year	~~Benefit of tax losses not recognized in the year~~		(33,450	~~(59,895~~)	)		(59,895	~~(57,851~~)	)
Income tax recovery (expense) recognized in the year	~~Income tax recovery (expense) recognized in the year~~	$	$–	–		$	$–	–

F-15

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

			Year Ended September 30, 2018				Year Ended September 30, 2017
		Year Ended September 30, 2019				Year Ended September 30, 2018
Deferred income tax assets (liabilities)	~~Deferred income tax assets (liabilities)~~
Net operating loss carry-forwards	~~Net operating loss carry-forwards~~	$	$2,563,850	~~3,538,871~~		$	$3,538,871	~~3,448,864~~
Oil and gas properties	~~Oil and gas properties~~		(2,043,926	~~(1,936,342~~)	)		(1,936,342	~~(173,294~~)	)
Equipment	~~Equipment~~		204,147	~~209,647~~			209,647	~~200,186~~
Valuation allowance	~~Valuation allowance~~		(724,071	~~(1,812,176~~)	)		(1,812,176	~~(3,475,756~~)	)
Net deferred income tax assets	~~Net deferred income tax assets~~	$	$–	–		$	$–	–

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.34

In accordance with generally accepted accounting principles, the Company has its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax returns for the previous five years remain subject to examination. The Company’s income tax returns in state income tax jurisdictions also remain subject to examination for the previous five years. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon audit. Therefore, the Company has no significant reserves for uncertain tax positions, and no adjustments to such reserves were required by generally accepted accounting principles. No interest or penalties have been levied against the Company and none are anticipated, therefore no interest or penalty has been included in the provision for income taxes in the consolidated statements of operations.

15.

COMMITMENTS

Office Lease

The Company is currently negotiating a one year extension to its office lease which expired on June 30, 2019. The Company has paid the landlord the monthly rentals it understands to be due as the landlord finalizes a lease agreement extension with the Company.

Compensation to Executive Officers

Concorde Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for $11,~~690~~306 per month (Cdn $15,000 per month). As of September 30, ~~2018~~2019, the Company did not owe Concorde Consulting any of this amount.

Rental Agreement

On June 19, 2017, the Company renewed its Edmonton office lease commencing effective on July 1, 2017 and expiring effective June 30, 2019. As part of the lease renewal the Company received the first 3 months of basic rent free. The quarterly payments due are as follows:

	USD $		Cdn $
2019 Q1 (October - December)	$	6,156	$	7,969
2019 Q2 (January - March)	$	6,156	$	7,969
2019 Q3 (April - June)	$	6,156	$	7,969

16.

CRUDE OIL AND NATURAL GAS PROPERTY INFORMATION (Unaudited)

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the results of the Company’s operations from oil producing activities from the Company’s Sawn Lake oil sands properties located in Alberta, Canada, for the years ending September 30, ~~2018~~2019 and ~~2017~~2018:

			September 30, 2018				September 30, 2017
		September 30, 2019				September 30, 2018
Oil sales after royalties	~~Oil sales after royalties~~	$	$–	–		$	$–	–
Production (Operating) expenses	~~Production (Operating) expenses~~		–	–			–	–
Depreciation, accretion and depletion	~~Depreciation, accretion and depletion~~		(44,457	~~(54,036~~)	)		(54,036	~~(75,232~~)	)
Oil sales less expenses	~~Oil sales less expenses~~		(44,457	~~(54,036~~)	)		(54,036	~~(75,232~~)	)
Income tax expenses	~~Income tax expenses~~		–	–			–	–
Results of operations from producing activities	~~Results of operations from producing activities~~	$	$(44,457	~~(54,036~~)	)	$	$(54,036	~~(75,232~~)	)

There was no production volumes or revenues for the fiscal years ending September 30, ~~2018~~2019 and ~~2017~~2018, due to a majority of the Company’s Joint Venture partners voting to temporarily suspend operations of the SAGD Project at the end of February 2016. In accordance with the Farmout Agreement the Company entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for the Company’s working interest portion of the costs of the SAGD Project before the execution of the Farmout Agreement in return for a net 25% working interest in two oil sands leases where the Company had a working interest of 50%. The Farmee is also required to provide funding to cover monthly administrative expenses of the Company provided that such funding shall not exceed $30,000 per month. The Farmee shall continue to cover the Company’s administrative costs up to $30,000 per month, under the Farmout Agreement, until completion in all substantial respects of the SAGD Project agreement entered into between the Company and the operator of the SAGD Project.

FOperating expenses are zero since at this time they are paid for under the Farmout Agreement. Transportation costs are included in these operating costs. The total share of the capital costs and operating expenses of the Company’s joint Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”), has been funded in accordance with the Farmout Agreement, at a net cost to the Company of $Nil. As required by the Farmout Agreement, the Farmee has since reimbursed the Company and or paid the operator in total approximately $20.6 million (Cdn $27.3 million) for the Farmee’s share and the Company’s share of the capital costs and operating expenses of the SAGD Project up to September 30, 2019. These costs include the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator (“OTSG”), production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells, construction of pipelines and expenditures to connect and tie-16in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the one SAGD well pair when the facility was producing; and the expenses associated with the monthly shut-in operations of the SAGD Project facility. The capital costs of the existing the SAGD Project steam plant facility, with pipelines and one SAGD well pair was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest basis, of which the Company’s share was covered under the Farmout Agreement. These capital costs do not include the start-up operating expenses to initiate oil production from the SAGD well pair.

Operating expenses are zero since at this time they were paid for under the Farmout Agreement. Transportation costs are included in these operating costs. The total share of the material costs and operating expenses of the Company’s joint Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”), has been funded in accordance with the Farmout Agreement, at a net cost to the Company of $Nil. As required by the Farmout Agreement, the Farmee has since reimbursed the Company and or paid the operator in total approximately $20.8 million (Cdn $27.0 million) for the SAGD Project for the Farmee’s share and the Company’s share of the capital costs and operating expenses of the SAGD Project up to September 30, 2018. These costs include the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator (“OTSG”), production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells and expenditures to connect these water wells with pipelines 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; and the monthly operating expenses associated with the steaming and production of the SAGD well pair up to September 30, 2018. The capital costs to complete the SAGD Project steam plant facility with one SAGD well pair was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest basis, of which the Company’s share was covered under the Farmout Agreement. These capital costs do not include the start-up operating expenses to initiate oil production from the SAGD well pair.35

SAGD Project Outlook - The SAGD Project has successfully shown the capability of producing oil from the Bluesky reservoir using steam. The SAGD Project has:

●

confirmed that the SAGD process works in the Bluesky formation at Sawn Lake;

●

established characteristics of ramp up through stabilization of SAGD performance;

● indicated the productive capability and steam-oil ratio (“SOR’”), of the reservoir; and

●

provided critical information required for well and facility design associated with future commercial development.

The first SAGD well pair, for the SAGD Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection commenced in May 2014 and production started in September of 2014. Production from this one SAGD well pair increased significantly over the 18-month period it produced. Over January and February of 2016 production from the SAGD Project averaged 615 bopd, on a 100% basis (154 bopd net to usthe Company), with an average SOR of 2.1 from one SAGD well pair. The SOR is reflective of the amount of steam needed to produce one barrel of oil. This SAGD Project was temporarily suspended at the end of February 2016. ~~The Company anticipates that a reactivation of the existing SAGD Project facility and current SAGD well pair will be part of a potential commercial expansion.~~ In early May of 2016, an amended application was submitted to the Alberta Energy Regulator (“AER”) for ana commercial expansion of the existing SAGD Project facility site ~~which~~and ~~would~~received ~~potentially~~regulatory ~~increase~~approval ~~the~~in ~~operation~~December ~~for up to a total of eight SAGD well pairs~~2017. This expansion application sought approval to expand the ~~current~~existing SAGD Project facility site to 3,200 bopd (100% basis). The Company anticipates that only five SAGD well pairs will need to be operating to achieve this production level. The ~~expanded~~Company ~~facility~~anticipates ~~will~~that bethe ~~designed~~commercial expansion to ~~handle up to~~ 3,200 bopd. ~~The~~(100% ~~AER~~basis) ~~approval~~would ~~for~~include ~~this~~the ~~expansion~~reactivation of the ~~Company’s~~ existing ~~SAGD~~ ~~Project~~demonstration ~~was~~project ~~granted~~SAGD infacility ~~December~~and ofexisting ~~2017.~~SAGD well ~~While~~pair, the ~~joint~~drilling ~~venture~~of ~~has~~an ~~not~~additional ~~yet~~four ~~approved~~wellpairs toand ~~expand~~expansion of the existing SAGD ~~Project~~ facility~~, currently~~ to generate the additional necessary steam. The SAGD Project continues to move forward with completing detailed engineering and ~~identification~~assessing ofpotential ~~long~~marketing arrangements ~~lead~~for ~~time~~the ~~items~~commercial ~~towards~~development ~~potential~~ expansion to 3,200 bopd ~~and~~(100% ~~future commercial development at Sawn Lake~~basis).

Capitalized Costs Relating Specifically to the SAGD Project

The Company entered into a Farmout Agreement dated July 31, 2013, whereby the Company’s ~~operating~~ costs of the SAGD Project are paid in full by the Farmee in ~~accordance~~ accordance with the Farmout Agreement; therefore, the Company has not capitalized any of the capital costs and operating expenses paid by the Farmee to the operator of the SAGD Project. See Note 4 herein “Capitalization of Costs Incurred in Oil and Gas Activities”.

Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development

See Note 5 herein “Exploration Activities”.

F-17. Subsequent Event Note

On October 28, 2019, Provident Premier Master Fund Ltd. (the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”) in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim had been filed on November 1, 2018 but the Company states that it had never been served so the Company was not aware of it.

The Plaintiff claims that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all petroleum substances produced, saved and marketed from six of the Company's oil sands leases located within the Company's Sawn Lake properties. The Plaintiff further claims that on September 22, 2006, Nearshore and Gemini Strategies LLC (“Gemini”) entered into a royalty conveyance agreement whereby Nearshore sold 1% of the GORR to Gemini. The Plaintiff further states that Gemini acquired the 1% GORR as agent for Provident, Grey K Fund LP (“Grey K”) and Grey K Offshore Fund Ltd. (“Grey K Offshore”). The Plaintiff further claims that on September 22, 2006, Gemini delivered a notice of assignment, in accordance with the 1993 Canadian Association of Petroleum Landmen Assignment Procedure (the “1993 CAPL”), to the grantors of the 1% GORR, novating Provident (66.67%, net 0.6667%), Grey K (19.33%, net 0.1933%) and Grey K Offshore (14%, net 0.14%) into the GORR agreement. The Plaintiff further claims that on September 2, 2009, any legal title in the GORR beneficially owned by Grey K and Grey K Offshore vested in the Crown in right of Alberta pursuant to Section 229(1) of the Business Corporations Act and pursuant to section 15 of the Unclaimed Personal Property and Vested Property Act. The Plaintiff further claims that the GORR was payable by one or more of the Defendants to Provident and that the Defendants are in breach of the GORR agreement by failing to pay the GORR. Despite the allegation within the claim that the GORR was payable to each of Provident, Grey K and Grey K Offshore, the only Plaintiff named in the Amended Statement of Claim is Provident and relief is only being sought by Provident in relation to its purported 0.67% interest.

The Company continues to deny the validity of the Purported 6.5% Royalty in the first instance. As well, if the Purported 6.5% Royalty was valid, which is denied, it was not a gross overriding interest, but rather an overriding interest, which allowed for the deduction of operating and marketing costs. The Company plans to vigorously defend itself against the Plaintiff’s claims.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

~~On July~~During ~~14, 2017,~~ the ~~Board~~fiscal ofyears ~~Directors~~ended September 30, ~~acting~~2019 asand ~~the~~2018, ~~Audit~~there ~~Committee~~were ofno ~~our~~changes ~~Company~~in, ~~approved~~or ~~the~~disagreements ~~dismissal of Sadler~~with, ~~Gibb & Associates, LLC (“Sadler Gibb”) as~~ our ~~Company’s~~ independent ~~registered~~accountant ~~public~~on accounting ~~firm. Sadler Gibb was engaged by us on October 6, 2015 to audit our consolidated financial statements for the fiscal year ending September 30, 2015~~ and ~~to perform reviews of our unaudited quarterly~~ financial ~~information for the periods ending December 31, 2015, March 31, 2016~~disclosure ~~and June 30, 2016~~matters. ~~Sadler Gibb audited our Company’s consolidated financial statements for the fiscal years ending September 30, 2013 and September 30, 2014.~~

In connection with our audited consolidated financial statements for the fiscal years ending September 30, 2013 and September 30, 2014, Sadler Gibb’s audit reports did not contain an adverse opinion or a disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope, or accounting principles.

The Board of Directors of our Company were dissatisfied with the length of time that it was taking to complete the audit of our financial statements for the fiscal year ending September 30, 2015. Differences of opinion between our Company and Sadler Gibb resulted in significant delays in the filing our consolidated financial statements. These differences and the reasons for the delays were not resolved prior to the dismissal of Sadler Gibb, and therefore Sadler Gibb did not complete its audit and render a report of its opinion on our consolidated financial statements for the fiscal year ended September 30, 2015.

There are no “reportable events” listed in paragraphs (A) through (D) of Item 304(a)(1)(v) of Regulation S-K.

Management of our Company discussed the disagreements with our Board of Directors and Sadler Gibb. We provided to Sadler Gibb a copy of the disclosures contained in our current report on Form 8-K, as filed with the commission on July 20, 2107, and requested that Sadler Gibb provide us with a letter, addressed to the U.S. Securities and Exchange Commission, stating whether or not Sadler Gibb agrees with our statements. A copy of Sadler Gibb’s response letter is incorporated by reference as exhibit 16.1 as filed with our current report on Form 8-K filed on July 20, 2017.

Our Company’s Board of Directors, acting as the Audit Committee, engaged Turner, Stone & Company, L.L.P., (“Turner Stone”) as our new independent registered public accounting firm, effective July 14, 2017, to audit and render an opinion on our consolidated financial statements for the fiscal years ending September 30, 2015 and September 30, 2016 and to review our quarterly consolidated financial statements for the periods ending December 31, 2015, March 31, 2016 and June 30, 2016. Our Company authorized Sadler Gibb to respond fully to the inquiries of Turner Stone. Our Company provided Turner Stone with our current report on Form 8-K, as previously filed, for its review and had given Turner Stone the opportunity to furnish to us a letter addressed to the U.S. Securities and Exchange Commission containing any new information, clarification of our Company’s expression of its views, or the respects in which it does not agree with the statements made by our Company as disclosed in our current report on Form 8-K filed on July 20, 2017.

ITEM 9A.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the fiscal year ended September 30, ~~2018~~2019, an evaluation of the effectiveness of our “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) was carried out under the supervision and with the participation of our principal executive officer and principal financial officer. Based upon that evaluation our principal executive officer and principal financial officer have concluded that as of the end of that fiscal year, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

It should be noted that while our principal executive officer and principal financial officer believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that our disclosure controls and procedures or internal control over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) to provide reasonable assurance regarding the reliability of our financial reporting and consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Our management, which included our principal executive officer and principal financial officer, assessed our internal control over financial reporting as of September 30, ~~2018~~2019. This assessment was based on criteria for effective internal control over financial reporting described in the internal control integrated framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that, as of September 30, ~~2018~~2019, our internal control over financial reporting was effective.

Attestation Report of the Independent Registered Public Accounting Firm

We are a smaller reporting and emerging growth company within the meaning of Rule 12b-2 under the Exchange Act. Therefore, this Annual Report is not required to include an attestation report of our independent registered public accounting firm, with respect to our internal control over financial reporting. Turner Stone’s audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of our internal control over financial reporting. Accordingly, Turner Stone expressed no such opinion on our internal control over financial reporting as of September 30, ~~2018~~2019.

Changes in Internal Control Over Financial Reporting

There was no change in our internal controls over financial reporting during the year end covered by this Annual Report on Form 10-K that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

ITEM 9B.

OTHER INFORMATION

Our Company reported all information that was required to be disclosed on Form 8-K during the fourth quarter of the fiscal year ended September 30, ~~2018~~2019, as covered by this Annual Report.

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PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors and Executive Officers

As of September 30, ~~2018~~2019, the directors and executive officers of Deep Well are as follows:

Name	Age	Director Since	Position/Office
Dr. Horst A. Schmid	8586	2004	Director and Chairman of the Board, President and Chief Executive Officer
Mr. Said Arrata	7879	2011	Director
Mr. Satya Brata Das	6263	2011	Director
Mr. Pascal Nodé-Langlois	7172	2013	Director
Mr. Colin P. Outtrim	6869	2014	Director
Mr. David Roff	4748	2006	Director
Mr. Curtis Sparrow	6162	2004	Director and Chief Financial Officer, Corporate Secretary and Treasurer
Mr. Malik Youyou	6566	2008	Director

Biographies of Directors and Executive Officers

Brief biographies of the directors and executive officers of Deep Well are set forth below. All directors hold office until the next shareholders’ meeting or until their death, resignation, retirement, removal, disqualification or until their successors have been elected and qualified. Vacancies in the existing Board may be filled by majority vote of the remaining directors. Officers of our Company serve at the will of the Board. As of September 30, ~~2018~~2019, there were no written employment contracts outstanding for officers, other than the consulting contracts as disclosed ~~herein~~in this Annual Report on Form 10-K.

Dr. Horst A. Schmid has served as director and Chairman of the Board of Deep Well since February 6, 2004. Since June 29, 2005, he has been the Chief Executive Officer and President of Deep Well. From September 1996 to present, Dr. Schmid has been the director, President and Chief Executive Officer of Portwest Investment Ltd., a private firm, located in Edmonton, Alberta, Canada. Prior to that, Dr. Schmid spent 15 years as Cabinet Minister for the Government of Alberta and 10 years as Commissioner General for Trade and Tourism for the province of Alberta. During that time, he was involved in numerous successful overseas negotiations for the Alberta oil and gas industry, achieving major contracts for Alberta exploration and production service companies. He is the recipient of many Canadian and international awards for his accomplishments. Dr. Schmid received an Honorary Law Degree from the University of Alberta.

Mr. Said Arrata has served as director of Deep Well since March 8, 2011. Mr. Arrata is a highly experienced energy executive who brings a sophisticated understanding of energy company development to the Deep Well Board. Mr. Arrata is the chairman of the board of directors and chief executive officer of Sea Dragon Energy Inc., a firm domiciled in Calgary, Alberta, devoted exclusively to overseas production, and concentrated in Egypt. In 2007 the company he co-founded, Centurion Energy, was sold for $1.2 billion to Dana Gas Inc. and Mr. Arrata subsequently established Sea Dragon Energy Inc. Since May of 2007, Mr. Arrata has been a board member of Dan Gas Inc., a company which operates oil and gas concessions in Egypt and the Province of Kurdistan. Reputed as a company-builder, he focused on building maximum value for shareholders during his more than 40 years in the oil and gas industry during which he held management and board positions with major oil and gas companies in Canada and overseas. Mr. Arrata holds a B.Sc. degree in Petroleum Engineering along with several post-graduate accreditations at various universities in North America and is an active member of several professional engineering and industry associations.

Mr. Satya Brata Das has served as director of Deep Well since March 8, 2011. Mr. Satya Brata Das is a seasoned strategist, author, board director and policy guru. Mr. Das’ guidance and counsel is highly valued in the public, private and philanthropic sectors. Mr. Das advised on more than 50 major files for the governments of Canada, Alberta, and municipalities. Mr. Das’ private sector engagement ranges from start-ups to listed firms. Building on a distinguished career in journalism in the last quarter of the 20th century, Mr. Das launched his advisory firm Cambridge Strategies Inc. at the turn of the millennium. Mr. Das’ proven skills in integrating the political, economic, societal and cultural dimensions of policy challenges have brought effective results to professional and voluntary endeavours. Mr. Das pioneered values-based public policy, using quantitative measures of citizen values to win social license and widespread societal support. Mr. Das is a frequent commentator and public speaker in both national languages, in media and on stage. A best-selling author, Mr. Das’ books include “Dispatches from a Borderless World”; “The Best Country: Why Canada Will Lead the Future”, ~~and~~ “Green Oil: Clean Energy for the 21st Century?”, and “Us”. Mr. Das’ volunteer work is deeply informed with a lifelong commitment to human rights as a way of life, and the principles of human dignity espoused by M.K. Gandhi.

Mr. Pascal Nodé-Langlois has served as a director of Deep Well since December 4, 2013. Mr. Nodé-Langlois is a French entrepreneur with a broad experience in banking. In 1975, he founded in Switzerland, the company Stock and Commodity Services SA (“SCS”). In 1991, SCS became Banque SCS Alliance SA (BSA), a fully licensed Swiss bank with branches in Switzerland and subsidiaries abroad. In 2006, after a consistent career of more than 30 years as the principal owner, Managing Director and Chairman of the Board of BSA (previously SCS), Mr. Nodé-Langlois sold his stake in the bank. In 2007, he founded a new financial boutique, in Luxembourg: Voltaire Group SA. This company operates as a holding company. It acquires majority participations and/or creates operating companies with the aim to cover a large portion of the different financial services corresponding to the field of expertise that Mr. Nodé-Langlois developed during his previous activity in banking. Its main present participation is PARfinance SA, a Swiss registered wealth management company.

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Mr. Colin P. Outtrim has served as director of Deep Well since November 17, 2014. Mr. Outtrim is a highly experienced petroleum engineer bringing with him extensive reservoir appraisal knowledge to the Company. Mr. Outtrim has over 40 years of experience in the global petroleum reserves and resources industry and has conducted and or participated in several hundred reservoir engineering and economic evaluation projects covering oil, gas and geothermal properties in all parts of the world having asset values from between one million to 20 billion dollars. Early in his career he worked with the Alberta Government Energy Resources and Conversation Board (now known as the Alberta Energy Regulator or “AER”) as a Reserves Engineer assessing the Alberta oil sands, at which time he also published and co-authored a paper entitled “The Oil Sands Reserves of Alberta”. From 1992 to 2004, he was the co-founder, President and CEO of Outtrim Szabo Associates Ltd. which served petroleum companies undertaking energy developments around the world. In 2004, Outtrim Szabo Associates Ltd. was acquired by DeGolyer and Mr. Outtrim became president and a director of DeGolyer until his retirement in 2012. From 2008 to 2012, the Company engaged DeGolyer to prepare the Company’s independent reserves and resources analysis reports, at which time Mr. Outtrim was providing independent consulting engineering services to the Company through DeGolyer. His career has provided him broad experience reporting to audit committees as a “qualified reserves evaluator and auditor”. He is one of a few expert members from around the world selected to sit on and serve as a technical member of the Experts Group sub-committee on the United Nations Economic Commission for Europe, the United Nations Framework Classification for the standardization of petroleum reserves and resource definitions, and has recently completed a three-year term on the board of trustees of the Society of Petroleum Engineers Canadian Educational Trust Fund as trustee and treasurer. He is currently serving as director and reserves audit committee chairman of CaiTerra International Energy Corporation and currently provides reservoir engineering advisory services to Tallahassee Resources Inc. He is also the past chairman of the Petroleum Society of the Canadian Institute of Mining. Mr. Outtrim holds a ~~Bachelors~~Bachelor of Applied Science in Geological Engineering from the University of British Columbia and is a registered Petroleum Engineer. Mr. Outtrim completed his professional qualifications at the highest level with the Institute of Corporate Directors (“ICD”) and attained his ICD.D designation.

Mr. David Roff has served as a director of Deep Well since April 3, 2006. Mr. Roff is the Vice President, Business Development at Cranson Capital, an Exempt Market Dealer a position he has held since Sept 2017. He is also a real estate advisor to Globalive Capital a position he has held since April 2015. Globalive Capital is a family office. Mr Roff is also co-president of Brave Investment Corporation, a private consulting and investment company and has held this position since 2001. He has over twenty years experience investing in, building and operating companies. Mr. Roff is a Chartered Professional Accountant and obtained his designation while working at Coopers & Lybrand Consulting. He also has a B.A. degree from the University of Western Ontario. Mr. Roff a director of Findev (FDI).

Mr. Curtis James Sparrow has served as director of Deep Well since February 6, 2004. Mr. Sparrow has also been the Chief Financial Officer, Corporate Secretary and Treasurer of Deep Well. Since the mid-1980s, Mr. Sparrow has been a self-employed management consultant specializing in the natural resource sector. Mr. Sparrow has been involved in the oil and gas industry in various capacities for over 38 years. He has held directorships and senior officer positions with junior exploration and development companies before becoming a self-employed consultant. He has also participated in the marketing side of the oil and gas industry, and was part of an acquisition team formed to assess and develop a bid for a multi-billion dollar integrated oil company. His experience also includes corporate and project management, international businesses and mining. Mr. Sparrow is a National Association of Corporate Directors (“NACD”) Governance Fellow. He has demonstrated his commitment to boardroom excellence by completing NACD’s comprehensive program of study for corporate directors. He supplements his skill sets through ongoing engagement with the director community, and access to leading practices. The NACD is the recognized authority focused on advancing exemplary board leadership and establishing leading boardroom practices. Mr. Sparrow received his Bachelor of Science Degree in Engineering and Master’s Degree in Business Administration from the University of Alberta. Mr. Sparrow is also a registered Professional Engineer a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA), the Society of Petroleum Engineers (SPE), and the American Finance Association (AFA).

Mr. Malik Youyou has served as director of Deep Well since August 20, 2008. Mr. Youyou is an experienced international entrepreneur, investor and director of several companies. With more than three decades of business experience in highly competitive global markets, beginning in his native France, Mr. Youyou brings a strong international perspective to Deep Well's Board. Mr. Youyou has created and led several companies involved in the development, branding, and marketing of luxury goods from leading international houses.

Family Relationships

There are no family relationships among the directors and executive officers of our Company.

Involvement in Certain Legal Proceedings

The following does not describe any past legal proceeding to which Deep Well or its subsidiaries are a party. In the past ten years:

No bankruptcy petition has been filed by or against any business of which any current director was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time.

No current director has been convicted in a criminal proceeding and is not subject to a pending criminal proceeding (excluding traffic violations and other minor offenses).

No current director has been the subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities.

No current director has been the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the right of such person to engage in any activity described in paragraph (f)(3)(i) of section 229.401 of Regulation S-K, or to be associated with persons engaged in any such activity.

No current director has been found by a court of competent jurisdiction in a civil action or by the SEC to have violated a Federal or State securities law that has not been reversed, suspended, or vacated.

No current director has been found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law that has not been subsequently reversed, suspended or vacated.

No current director has been the subject of, or a party to, any Federal or State judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of any federal or state securities or commodities law or regulation; any law or regulation respecting financial institutions or insurance companies including, but not limited to, a temporary or permanent injunction, order or disgorgement or restitution, civil money penalty or temporary or permanent cease-and-desist order, or removal or prohibition order; or any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity.

No current director has been the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization, any registered entity, or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

Section 16 (a) Beneficial Ownership Reporting Compliance

~~Section 16(a)~~Based ofsolely on the ~~Exchange~~review ~~Act~~of ~~requires~~Forms ~~our~~3 ~~Company’s~~and 4 ~~officers,~~received ~~directors~~by ~~and~~us ~~persons~~during ~~who~~the ~~beneficially~~September ~~own~~30, ~~more~~2019 ~~than~~fiscal ~~10%~~year, ofas ~~a registered~~required ~~class~~under ofSection ~~our~~16(a)(2) ~~Company’s~~of ~~equity~~the ~~securities~~Exchange toAct, ~~file~~all ~~reports~~ of ~~ownership~~our directors and ~~changes~~officers inreported ~~ownership~~all ~~with~~their ~~the~~transactions ~~SEC, and~~as torequired ~~furnish~~on toa ~~our~~Form ~~Company~~4, ~~copies~~on ofa ~~such~~timely ~~reports~~basis.

Based solely on the review of Forms 3 and 4 received by our Company during the September 30, 2018 fiscal year, as required under Section 16(a)(2) of the Exchange Act, the following directors, although they reported all their transactions as required on either a Form 3 or Form 4, did not report on a timely basis: Dr. Horst A. Schmid filed one Form 4 late (relating to 6 transactions), Mr. Said Arrata filed one Form 4 late (relating to 3 transactions), Mr. Satya Das filed one Form 4 late (relating to 3 transactions), Mr. David Roff filed one Form 4 late (relating to 3 transactions), Mr. Curtis Sparrow filed one Form 4 late (relating to 6 transactions), and Mr. Malik Youyou filed one Form 4 late (relating to 3 transactions).

Code of Ethics

Our Company has adopted a formal Code of Business Conduct and Ethics policy governing our principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, including our directors and employees, to promote honest and ethical conduct, full, fair, accurate, understandable and timely disclosure in our reports to the SEC, and compliance with applicable governmental laws, rules and regulations. A copy of our Code of Business Conduct and Ethics policy may be obtained, free of charge, from our website at www.deepwelloil.com ~~or DWOG.com~~, or by written request addressed to the Corporate Secretary of Deep Well Oil & Gas, Inc., Suite 700, 10150 – 100 Street NW, Edmonton, Alberta, T5J 0P6, Canada. Incorporated by reference, as Exhibit 14.1, is a copy of our Code of Business Conduct and Ethics policy filed with the SEC on January 13, 2015.

Changes to Security Holder Director Nomination Procedures

Our Company currently does not have a specific policy in place with respect to evaluating candidates for director nominees at this time. However, any shareholder proposals to be presented at our next annual meeting of shareholders (including the inclusion of shareholder director nominees) must be given in writing to our Company, along with proof of ownership of our stock in accordance with Rule 14a-8(b)(2), and received at our Company’s principal executive office, located at Suite 700, 10150 – 100 Street NW, Edmonton, Alberta, T5J 0P6. Any such proposal must comply with the rules pursuant to Rule 14a-8 under the Exchange Act and in accordance with our Company’s Bylaws.

Corporate Governance

Director Independence

Our Board with the assistance of management, reviews and determines director independence requirements for each director, based on the NASDAQ standards for director independence as set forth by the NASDAQ Stock Market Rule 5605(a)(2) and pursuant to Rule 10A-3 of the Exchange Act of 1934. Our Board determined that as of September 30, ~~2017~~2019 and 2018, the Company’s Board consisted of five independent and three non-independent directors. It was determined that Dr. Horst A. Schmid and Mr. Curtis Sparrow, who serve as directors of our Company, are not independent because they serve our Company as President and CEO and Chief Financial Officer, respectively. It was also determined that Mr. Malik Youyou, who serves as a director of our Company, is not independent because he owns a controlling interest of our Company’s issued and outstanding common stock. The directors of our Company, when they became directors and our Company’s opinion as to each director’s independence are as follows:

Name	Year ~~When First~~ Appointed ~~as Director~~	Director Independence
Dr. Horst A. Schmid	2004	Non-independent director – Chairman of the Board
Mr. Said Arrata	2011	Independent director
Mr. Satya Brata Das	2011	Independent director
Mr. Pascal Nodé-Langlois	2013	Independent director
Mr. Colin P. Outtrim	2014	Independent director
Mr. David Roff	2006	Independent director
Mr. Curtis Sparrow	2004	Non-independent director
Mr. Malik Youyou	2008	Non-independent director

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Corporate Governance and Nominating Committee

Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of the Corporate Governance and Nominating committee. This committee currently does not have a specific policy in place with respect to evaluating candidates for director nominees at this time.

Any shareholder proposals to be presented at our next annual meeting of shareholders (including the inclusion of shareholder director nominees) must be given in writing to our Company, along with proof of ownership of our stock in accordance with Rule 14a-8(b)(2), and received at our Company’s principal executive office, located at Suite 700, 10150 – 100 Street NW, Edmonton, Alberta, T5J 0P6. Any such proposal must comply with the rules pursuant to Rule 14a-8 under the Exchange Act and in accordance with our Company’s Bylaws. Our Company reserves the right to reject, rule out of order or take other appropriate action with respect to any proposal that does not comply with these and other applicable requirements, including conditions set forth in our bylaws and conditions established by the SEC. If our Company has its shareholder meeting by way of resolution any complying proposal will be considered at that time. It is recommended that shareholders submitting proposals direct them to our Corporate Secretary and utilize certified mail return receipt requested in order to provide proof of timely receipt. Copies of the bylaws are available by writing to our Company at the mailing address above or downloading them as previously filed on September 3, 2009 with the SEC on Form 8-K.

Audit Committee

Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of the Audit committee. Of our eight directors serving on our Board, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou have been determined by our Board not to be independent directors under director independence standards noted above. Our Board has determined that Mr. David Roff, as a director of our Company, is independent and is also recognized as an audit committee financial expert. Mr. Roff is a Chartered Professional Accountant, with a B.A. degree from the University of Western Ontario, and he worked as an auditor from 1995 to 1998.

Compensation Committee

Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of our Compensation committee. Of our eight directors serving on our Board, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou have been determined by our Board not to be independent directors under director independence standards noted above. During the September 30, ~~2018~~ 2019 fiscal year Dr. Horst A. Schmid and Mr. Curtis Sparrow served as officers of our Company.

On or about July 31, 2018, a majority of shareholders approved by written consent, on a non-binding basis, the compensation paid to our Company's named executive officers.

Reserves and Resources Committee

On January 3, 2015, our Board appointed a Reserves and Resources Committee consisting of four Board members, three of which are independent. Our Board appointed the following Directors: Mr. Said Arrata, Mr. Colin Outtrim, Mr. David Roff and Mr. Curtis Sparrow to serve on this committee and Mr. Colin Outtrim was appointed as chairman of the committee. Of our four members serving on this committee it was determined by our Board that Mr. Curtis Sparrow is not an independent member or director under director independence standards noted above.

The purpose of this committee is to assist our Board in monitoring: (i) the integrity of the independent reserves and resources estimates and related U.S. and Canadian regulatory disclosures of our Company; and (ii) the qualifications and independence of the independent reservoir engineers, geologists and geophysicists.

Our Company’s reserves, if any, and/or resources data and estimates are prepared by independent examination and evaluation of our Company’s production data, reservoir pressure data, logs, geological data, and offset analogies in compliance with SEC definitions and guidance and in accordance with generally accepted petroleum engineering principles. The technical persons employed by the independent reserves evaluators are required to meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the “Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information” promulgated by the Society of Petroleum Engineers. Our Company’s independent reserves evaluators are provided full access to complete and accurate information pertaining to our Company’s properties, and to all applicable personnel of our Company. Our Company’s reserves, if any, and/or resources estimates and process for developing such estimates are reviewed by our Company’s current Reserves and Resources Committee and approved by management. Management on behalf of our Board ensures compliance with SEC disclosure and internal control requirements along with verifying the independence of all third-party consultants. Our Company’s management is ultimately responsible for reserves, if any, and or resources estimates and reserves disclosures and ensuring that they are in accordance with the applicable regulatory requirements and industry standards and practices.

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ITEM 11.

EXECUTIVE COMPENSATION

~~At the~~On ~~Company’s~~July ~~2013 general meeting of shareholders held on September 17~~31, ~~2014~~2018, a majority of our shareholders approved on an advisory basis the compensation paid to the Company’s named executive officers (also known as “Say-on-Pay”). ~~and~~At the Company’s 2013 general meeting of shareholders held on September 17, 2014, a majority of our shareholders approved the frequency of which to hold the say-on-pay advisory vote on the compensation paid to the Company’s named executive officers be every three years. This non-binding “Frequency Vote” must be considered by our Company’s shareholders at least once every six years. We will have another non-binding vote on the frequency in which to hold an advisory vote on compensation paid to our Company’s named executive officers within six years from the last vote held on September 17, 2014.

Summary Compensation Table

The following table provides information about the compensation paid to, earned or received during the two fiscal years ended September 30, ~~2018~~2019 and September 30, ~~2017~~2018, by the executive officers listed below (the “Named Executive Officers”).

Executive Compensation Summary
Name and Principal Position	Fiscal Year Sept. 30	~~Fee~~		Fee		~~Bonus~~		Bonus		~~Stock Awards~~		Stock Awards		~~Option Awards~~		Option Awards		~~Non-Equity Incentive Plan Compensation~~		Non-Equity Incentive Plan Compensation		~~Non-qualified Deferred Compensation Earnings~~		Non-qualified Deferred Compensation Earnings		~~All Other Compensation~~		All Other Compensation		~~Total~~		Total
Dr. Horst A. Schmid (1)	~~2018~~2019	$	–	~~(2)~~$	–	$(2)	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	~~9,505~~	~~(2)~~$	4,591	$(2)	~~9,505~~	$	4,591	(5)
President and	~~2017~~2018	$	–	~~(2)~~$	–	$(2)	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	9,589	$(2)	–	$	9,589	(5)
Chief Executive Officer
Mr. Curtis Sparrow (3)	~~2018~~2019	$	~~139,050~~	~~(4)~~$	135,666	$(4)	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	~~5,119~~	~~(4)~~$	3,176	$(4)	~~144,169~~	~~(5)~~$	138,842	(5)
Chief Financial Officer	~~2017~~2018	$	~~144,234~~	~~(4)~~$	140,274	$(4)	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	–	$	~~3,869~~	~~(4)~~$	5,164	$(4)	~~148,103~~	~~(5)~~$	145,438	(5)

⁽¹⁾

Dr. Horst A. Schmid has served our Company as director and Chairman of the Board since February 6, 2004. Since June 29, 2005 to present Dr. Schmid has been the President and Chief Executive Officer of our Company.

(2) Portwest Investments Ltd. (“Portwest”), a company owned 100% by Dr. Horst A. Schmid, provided services as Chief Executive Officer and President to our Company for $Nil for the ~~2018~~2019 fiscal year and $Nil for the ~~2017~~2018 fiscal year. Portwest Investments Ltd. was reimbursed for expenses paid that were related to health care in the amount of ~~9,505 (Cdn~~ $124,~~305)~~591 for the ~~2018~~2019 fiscal year and $~~Nil~~9,589 for the ~~2017~~2018 fiscal year.

⁽³⁾

Mr. Curtis Sparrow has served our Company as director since February 6, 2004. Since February 9, 2004 Mr. Sparrow has been the Chief Financial Officer, Corporate Secretary and Treasurer of our Company.

(4) Concorde Consulting, a company owned 100% by Mr. Curtis Sparrow, provided services as Chief Financial Officer to our Company for $~~144~~135,~~169~~666 ~~(Cdn $180,000)~~ for the ~~2018~~2019 fiscal year and $~~148~~140,~~103~~274 ~~(Cdn $180,000)~~ for the ~~2017~~2018 fiscal year. Concorde Consulting was reimbursed for expenses paid that were related to health care in the amount of $53,~~119~~176 ~~(Cdn~~for ~~$6,626) related to~~ the ~~2018~~2019 fiscal year and $35,~~869~~164 ~~(Cdn~~for ~~$4,828) related to~~ the ~~2017~~2018 fiscal year.

(5) ~~Mr. Sparrow’s September 30, 2018 and 2017 fiscal year fees were converted to~~ US$ based on the average year-end exchange rates of $0.~~7725~~7537 and $0.~~8013~~7793, respectively.

Compensation Arrangements for Executive Officers

Our Company currently does not provide retirement benefits to its executive officers.

Our Company has entered into a contract with Concorde Consulting, a company owned 100% by Mr. Curtis Sparrow for providing services as Chief Financial Officer to our Company for Cdn$15,000 per month. As of September 30, ~~2018~~2019, our Company owed Concorde Consulting $Nil for services provided to our Company.

On June 20, 2013, and as herein reported under the Executive Compensation Summary table above, our Board granted Dr. Schmid and Mr. Sparrow, as directors of our Company, options to purchase 450,000 shares each of common stock at an exercise price of $0.05 per common share, one-third vesting immediately, one-third vesting on June 20, 2014, and one-third on June 20, 2015. Between June 8 to 10, 2018, five directors, two contractors and one employee of our Company, exercised a total of 3,150,000 of their option shares at an exercise price of $0.05 by way of a cashless exercise to acquire a total of 899,998 common shares of our Company, based upon the market value of our Company’s common stock of $0.07 per share on June 8, 2018, whereby 2,250,002 common shares were withheld by our Company to pay for the exercise price of the options. On June 19, 2018, one director of our Company acquired 300,000 common shares of our Company upon exercising his stock options, at an exercise price of $0.05 per common share for total gross proceeds to our Company of $15,000. The stock certificates from all of these exercises are currently held in escrow and, in addition, are restricted from trading upon final approval and release by the Management of our Company.

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On September 19, 2014, and as herein reported under the Executive Compensation Summary table above, our Board granted Dr. Schmid and Mr. Sparrow, as directors of our Company, options to purchase 600,000 shares of common stock at an exercise price of $0.38 per common share, one-third vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016. These options expire on September 19, 2019.

Outstanding Equity Awards Granted to Executive Officers at September 30, 2018

Options Awards (1)

Stock Awards

Name

Number of Securities Underlying Unexercised Options (#) Exercisable

Number of Securities Underlying Unexercised Options (#) Unexercisable

Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)

Option Exercise Price ($)

Option Expiration Date

Number of Shares or Units of Stock That Have Not Vested (#)

Market Value of Shares or Units of Stock That Have Not Vested ($)

Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)

Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)

Portwest Investments Ltd. (1)

1,200,000

–

0.38

09/19/2019

–

Concorde Consulting (2)

1,200,000

–

0.38

09/19/2019

–

(1) On September 19, 2014, our Board granted Portwest, options to purchase 1,200,000 shares of common stock at an exercise price of $0.38 per share of common stock, with one-half vesting immediately and one-half vesting on September 19, 2015. See the Executive Compensation table for more disclosure. As of the date of this report Portwest had not exercised any of these stock options.

(2) On September 19, 2014, our Board granted Concorde Consulting, options to purchase 1,200,000 shares of common stock at an exercise price of $0.38 per share of common stock, with one-half vesting immediately and one-half vesting on September 19, 2015. See the Executive Compensation table for more disclosure. As of the date of this report Concorde Consulting had not exercised any of these stock options.

Compensation of Directors

On November 28, 2005 and as amended on December 4, 2013, our Board adopted the Deep Well Oil & Gas, Inc. Stock Option Plan. The Stock Option Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Stock Option Plan is administered by our Board and permits options to acquire shares of Deep Well’s common stock to be granted to directors of our Company. The vesting of such director options will occur only if the holder of the options continues to provide services to us during the immediate annual period preceding the relevant vesting date. The options will terminate at the close of business five years from the date of grant.

On December 4, 2013, our Board appointed Mr. Pascal Nodé-Langlois as a director and in connection with the appointment our Board granted Mr. Nodé-Langlois an option to purchase 450,000 shares of common stock at an exercise price of $0.34 per share of common stock, 150,000 vesting immediately and the remaining vesting one-third on December 4, 2014, and one-third on December 4, 2015, with such options expiring on December 4, 2018. These options have since expired unexercised.

On September 19, 2014, our Board granted each of its directors, Dr. Horst A. Schmid, Mr. Said Arrata, Mr. Satya Das, Mr. Pascal Nodé-Langlois, Mr. David Roff, Mr. Curtis Sparrow and Mr. Malik Youyou, options to purchase 600,000 shares each of common stock at an exercise price of $0.38 per share of common stock, 200,000 vesting immediately and the remaining vesting one-third on September 19, 2015, and one-third on September 19, 2016, with such options expiring on September 19, 2019. These options have since expired unexercised.

On November 17, 2014, our Board appointed Mr. Colin Outtrim as a director and in connection with Mr. Outtrim’s appointment our Board granted Mr. Outtrim an option to purchase 600,000 shares each of common stock at an exercise price of $0.23 per share of common stock, 200,000 vesting immediately and the remaining vesting one-third on November 17, 2015, and one-third on November 17, 2016, with such options expiring on November 17, 2019. These options have since expired unexercised.

For the year ended September 30, 2019, our Company recorded no share-based compensation expense related to stock options (September 30, 2018 - $NIL). As of September 30, 2019, there was no unrecognized compensation cost related to option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.

For the year ended September 30, 2018, our Company recorded no share-based compensation expense related to stock options (September 30, 2017 - $2,314). As of September 30, 2018, there was no unrecognized compensation cost related to option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.

Director Compensation at September 30, 2018

Name

Fees Earned or Paid in Cash ($)

Stock Awards ($)

Option Awards ($)

Non-Equity Incentive Plan Compensation ($)

Nonqualified Deferred Compensation Earnings ($)

All Other Compensation ($)

Total ($)

Dr. Horst A. Schmid

Disclosed in the Summary Compensation Table above.

Mr. Said Arrata(1)

–

Mr. Satya Brata Das(2)

–

Mr. Pascal Nodé-Langlois(3)

–

Mr. Colin P. Outtrim(4)

–

Mr. David Roff(5)

–

Mr. Curtis James Sparrow

Disclosed in the Summary Compensation Table above.

Mr. Malik Youyou(6)

–

(1) Mr. Said Arrata has served our Company as director since March 8, 2011. Mr. Arrata has no outstanding unvested stock options.

(2) Mr. Satya Brata Das has served our Company as director since March 8, 2011. Mr. Das has no outstanding unvested stock options.

(3) Mr. Pascal Nodé-Langlois has served our Company as director since December 4, 2013. Mr. Nodé-Langlois has no outstanding unvested stock options.

(4) Mr. Colin P. Outtrim has served our Company as director since November 17, 2014. Mr. Outtrim has no outstanding unvested stock options.

(5) Mr. David Roff has served our Company as director since April 3, 2006. Mr. Roff has no outstanding unvested stock options.

(6) Mr. Malik Youyou has served our Company as director since August 20, 2008. Mr. Youyou has no outstanding unvested stock options.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

As of September 30, ~~2018~~2019, with respect to shares of Deep Well common stock that may be issued under our existing equity compensation plan, see Item 5 “Equity Compensation Plan Information” of this Annual Report on Form 10-K.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the number and percentage of the beneficial ownership of shares of Deep Well’s outstanding common stock as of November 30, ~~2018~~2019 by each person or group known by us to be the beneficial owner of more than 5%, and all of our directors and executive officers individually and as a group.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Name and Address of Beneficial Owner

Title of Class

Number of Shares Beneficially Owned (1) (2)

Percentage of Class Beneficially Owned

Nature of Beneficial Ownership

Malik Youyou (†) Director Sadovnicheskeya nab 69 Moscow 115035, Russia

Common

~~115~~114,~~456~~856,091

49.9481

%(3)

Direct and Indirect

MP West Canada SAS Beneficial Owner of 5% or more 51, Rue D’Anjou, Paris, 75008, France

Common

45,111,778

19.56

(4)

Direct

Dr. Horst A. Schmid (†) Director and Chairman of the Board, President and Chief Executive Officer Suite 700, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada

Common

53,~~451~~651,428

21.3558

%(5)

Direct and Indirect

Mr. Curtis J. Sparrow (†) Director, Chief Financial Officer, Corporate Secretary and Treasurer Suite 700, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada

Common

31,~~778~~978,571

~~1.63~~*

%(6)

Direct and Indirect

Mr. Satya Brata Das (†) Director Suite 710, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada

Common

1,907,381

*(7)

Direct and Indirect

Mr. Satya Brata Das (†) Director Suite 700, 10150 - 100 Street Edmonton, Alberta T5J 0P6 Canada

Common

1,307,381

(7)

Direct and Indirect

Mr. Said Arrata (†) Director #408, 600 Princeton Way SW Calgary, Alberta T2P 5N4 Canada

Common

1,~~785~~185,714

*(8)

Direct

Mr. Pascal Nodé-Langlois (†) Director c/o Parfinance SA 65 rue du Rhone 1204 Geneva, Switzerland

Common

1,644,311

*(9)

Indirect

Mr. David Roff (†) Director Suite 700, 10150 - 100 Street NW Edmonton, Alberta T5J 0P6 Canada

Common

848,155

(9)

Direct

Mr. David Roff (†) Director Suite 700, 10150 - 100 Street NW Edmonton, Alberta T5J 0P6 Canada

Common

1,448,155

*(10)

Direct

Mr. Pascal Nodé-Langlois (†) Director c/o Parfinance SA 65 rue du Rhone 1204 Geneva, Switzerland

Common

594,311

(10)

Indirect

Mr. Colin P. Outtrim (†) Director 331 Rocky Ridge Dr. NW Calgary, AB T3G 4P4 Canada

Common

~~600,000~~–

*(11)

Direct

(†) All Officers and Directors as a Group

Common

~~132~~124,~~071~~421,651

5753.1296

Direct and Indirect

Less than 1%

3244

⁽¹⁾

Under the rules of the SEC, a person or entity beneficially owns stock of a company if such person or entity directly or indirectly has, or shares the power to, vote or direct the voting, or the power to dispose or direct the disposition of such stock, whether through any contract, arrangement, understanding, relationship or otherwise. A person or entity is also deemed to be the beneficial owner of stock if such person or entity has the right to acquire either of such powers at any time within 60 days through the exercise of any option, warrant, right or conversion privilege or pursuant to the power to revoke a trust, a discretionary account or similar arrangement or pursuant to the automatic termination of a trust, discretionary account or similar arrangement.

(2) Based on 230,574,603 of our Company’s common shares issued and outstanding on November 30, ~~2018~~2019. For calculating the percentage of beneficial ownership separately for each person, his or her options, ~~warrants or both~~ that can be acquired within 60 days are included in both the numerator and the denominator. For the directors as a group, their collective options ~~and warrants~~ that can be acquired within 60 days are included in both the numerator and the denominator when calculating their group percentage ownership. ~~The following footnotes are based solely upon the review of Forms 3, 4, and Schedule 13Ds filed with the SEC by each person or company below.~~

(3) Mr. Malik Youyou has served the Company as director since August 20, 2008. As of November 30, ~~2018~~2019, Mr. Youyou beneficially owns ~~115~~114,~~456~~856,091 shares of our common stock, of which (i) 104,783,897 shares are held by Mr. Youyou directly; and (ii) 10,072,194 shares are held indirectly by Westline Enterprises Limited, a corporation 100% owned by Mr. Youyou~~; and (iii) Mr~~. Youyou presently directly holds exercisable options to acquire 600,000 shares of our Company’s common stock. Assuming the issuance of 600,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Youyou’s presently exercisable options, Mr. Youyou would beneficially own 49.94% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. Youyou has ~~not exercised any of these currently outstanding options and without the exercise of Mr. Youyou’s outstanding options, Mr. Youyou has~~ a 49.81% ownership of our Company’s issued and outstanding common stock.

(4) Based solely on our statement of security holder listing report received from our transfer agent on November 30, ~~2018~~2019, MP West Canada ~~SAS~~S.A.S. owns 45,111,778 shares of our common stock and based on this report MP West Canada ~~SAS~~S.A.S. owns 19.56% of our Company’s issued and outstanding common stock. On February 1, 2017, PT Pertamina (Persero) ("PT Pertamina") indirectly acquired MP West Canada S.A.S. as a result of the successful completion of its voluntary tender offer for all the outstanding securities, that it did not already own of Etablissementes Maurel & Prom ("M&P"). M&P is the direct beneficial owner of all of the outstanding share capital of MP West Canada S.A.S. As a result of the tender offer, PT Pertamina, through Pertamina Internasional Eksplorasi dan Produksi ("Pertamina Internasional"), has acquired a majority of the outstanding shares of M&P. Among the assets of MP West Canada S.A.S. that were acquired by PT Pertamina were 45,111,778 shares of common stock of our Company. As a result of the completion of the tender offer, PT Pertamina became the indirect beneficial owner of 45,111,778 shares of the our Company's common stock, which continue to be held of record and beneficially owned by MP West Canada S.A.S.

(5) Dr. ~~Horst A.~~ Schmid has served our Company as director and Chairman of the Board since February 6, 2004. Dr. Schmid has also served our Company as President and Chief Executive Officer since June 29, 2005. As of November 30, ~~2018~~2019, Dr. Schmid beneficially owns 53,~~451~~651,428 shares of our Company’s common stock, of which (i) 235,714 shares are held directly; and (ii) 2,565,714 shares are held indirectly by Portwest Investments Ltd. and another 850,000 shares are held indirectly by Trans World Factors Inc., both of which are private corporations 100% owned by Dr. Schmid~~; (iii) Dr~~. Schmid presently indirectly holds exercisable options through Portwest Investments Ltd., to acquire 1,200,000 shares of our Company’s common stock; and (iv) Dr. Schmid presently directly holds exercisable options to acquire an additional 600,000 shares of our Company’s common stock. Assuming the issuance of 1,800,000 shares of our Company’s common stock, pursuant to the exercise of Dr. Schmid’s presently exercisable options, Dr. Schmid would beneficially own 2.35% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Dr. Schmid has ~~not exercised any of these currently outstanding options and without the exercise of Dr. Schmid’s outstanding options, Dr. Schmid has~~ a 1.58% ownership of our Company’s issued and outstanding common stock.

(6) Mr. Sparrow has served the Company as director and Chief Financial Officer since February 9, 2004. As of November 30, ~~2018~~2019, Mr. Sparrow beneficially owns 31,~~778~~978,571 shares of our Company’s common stock, of which (i) 600,000 shares are held directly; and (ii) 1,378,571 shares are held indirectly by Concorde Consulting, a private corporation owned 100% by Mr. Sparrow~~; (iii) Mr~~. Sparrow presently indirectly holds exercisable options through Concorde Consulting, to acquire 1,200,000 shares of our Company’s common stock; and (v) Mr. Sparrow also presently directly holds exercisable options to acquire an additional 600,000 shares of our Company’s common stock. Assuming the issuance of 1,800,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Sparrow’s presently exercisable options, Mr. Sparrow would beneficially own 1.63% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. Sparrow has ~~not exercised any of these currently outstanding options and without the exercise of Mr. Sparrow’s outstanding options, Mr. Sparrow has~~ a 0.86% ownership of our Company’s issued and outstanding common stock.

(7) Mr. ~~Satya Brata~~ Das has served our Company as director since March 8, 2011. As of November 30, ~~2018~~2019, Mr. Das beneficially owns 1,~~907~~307,381 shares of our Company’s common stock, of which (i) 475,714 shares are held directly; and (ii) 831,667 are held indirectly by Cambridge Strategies Inc., a company 50% owned by Mr. Satya Brata Das and 50% owned by his wife~~; (iii) Mr~~. Das also presently indirectly holds through Cambridge Strategies Inc., exercisable options to acquire an additional 600,000 shares of our Company’s common stock. Assuming the issuance of 600,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Das’ presently exercisable options, Mr. Das would beneficially own 0.83% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. Das has ~~not exercised any of these currently outstanding options and without the exercise of Mr. Das’ outstanding options, Mr. Das has~~ a 0.57% ownership of our Company’s issued and outstanding common stock.

(8) Mr. ~~Said~~ Arrata has served our Company as director since March 8, 2011. As of November 30, ~~2018~~2019, Mr. Arrata beneficially owns 1,~~785~~185,714 shares of our Company’s common stock of which ~~(i)~~ 1,185,714 shares are held directly~~; and (ii) Mr~~. Arrata presently holds directly exercisable options to acquire an additional 600,000 shares of our Company’s common stock. Assuming the issuance of 600,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Arrata’s presently exercisable options, Mr. Arrata would beneficially own 0.77% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. Arrata has ~~not exercised any of these currently outstanding options and without the exercise of Mr. Arrata’s outstanding options, Mr. Arrata has~~ a 0.51% ownership of our Company’s issued and outstanding common stock.

33(9) Mr. Roff has served our Company as director since April 3, 2006. As of November 30, 2019, Mr. Roff beneficially owns 848,155 shares of our Company’s common stock of which 848,155 shares are held directly. As of November 30, 2019, Mr. Roff has a 0.37% ownership of our Company’s issued and outstanding common stock.

(910) Mr. ~~Pascal~~ Nodé-Langlois has served our Company as director since December 4, 2013. As of November 30, ~~2018~~2019, Mr. Nodé-Langlois beneficially owns 1594,~~644,~~311 shares of our Company’s common stock of which ~~(i)~~ 594,311 shares are held indirectly through Voltaire Group SA, a company 100% owned by Mr. Nodé-Langlois~~; and (ii) Mr~~. Nodé-Langlois presently indirectly holds through Voltaire Group SA, exercisable options to acquire an additional 1.050,000 shares of our Company’s common stock. Assuming the issuance of 1,050,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Nodé-Langlois’ presently exercisable options, Mr. Nodé-Langlois would beneficially own 0.71% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. Nodé-Langlois has ~~not exercised any of these currently outstanding options and without the exercise of Mr. Nodé-Langlois’ outstanding options, Mr. Nodé-Langlois has~~ a 0.26% ownership of our Company’s issued and outstanding common stock.

(1011) Mr. ~~David~~Outtrim ~~Roff~~ has served ~~our~~the Company as director since ~~April 3, 2006. As of~~ November 3017, ~~2018, Mr~~2014. Roff beneficially owns 1,448,155 shares of our Company’s common stock of which (i) 848,155 shares are held directly; and (ii) Mr. Roff presently directly holds exercisable options to acquire an additional 600,000 shares of our Company’s common stock. Assuming the issuance of 600,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Roff’s presently exercisable options, Mr. Roff would beneficially own 0.63% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. ~~Roff~~Outtrim ~~has~~does not ~~exercised~~own any ofissued ~~these currently outstanding options~~ and ~~without the exercise of Mr. Roff’s~~ outstanding ~~options,~~common ~~Mr.~~stock ~~Roff has a 0.37% ownership~~ of our Company~~’s issued and outstanding common stock~~.

(11) Mr. Colin Outtrim has served the Company as director since November 17, 2014. As of November 30, 2018, Mr. Outtrim beneficially owns 600,000 shares of our Company’s common stock of which Mr. Outtrim presently directly holds exercisable options to acquire 600,000 shares of our Company’s common stock. Assuming the issuance of 600,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Outtrim’s presently exercisable options, Mr. Outtrim would beneficially own 0.26% of our Company’s outstanding common stock. As of November 30, 2018, Mr. Outtrim has not exercised any of these currently outstanding options and without the exercise of Mr. Outtrim’s outstanding options, Mr. Outtrim has a 0% ownership of our Company’s issued and outstanding common stock.45

Changes in Control

Except as described below, Deep Well is not aware of any arrangement that may result in a change in control of Deep Well or its subsidiary companies.

As of November 30, ~~2018~~2019, and based solely on Mr. Malik Youyou’s filed Form 4s and most recent Schedule 13D, Mr. Youyou, a director of our Company, beneficially owns ~~115~~ 114,~~456~~856,091 common shares of Deep Well, representing 49.9481% of Deep Well’s outstanding shares of common stock ~~(assuming the exercise of all outstanding options held by Mr~~. ~~Youyou).~~

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Transactions with Related Persons

Our Board of Directors reviews and approves all related party transactions over $~~120~~10,000 ~~or such other amount as revised under Regulation S-K Item 404(a)~~. The standard applied by our Board in approving any related party transaction will be to confirm that the transaction is in the best interests of our Company without regard to the interests of the related party involved in the transaction.

For the fiscal year ending September 30, 2019 ~~2018~~ and September 30, ~~2017~~2018, we paid Concorde Consulting, a company 100% owned by Mr. Curtis James Sparrow, $~~139~~135,~~050~~666 and $~~144~~140,~~234~~274, respectively, for consulting services provided to our Company for professional services provided to our Company as Chief Financial Officer and Corporate Secretary. Mr. Sparrow is also a director of our Company.

Mr. Malik Youyou has served the Company as director since August 20, 2008. As of November 30, ~~2018~~2019, Mr. Youyou beneficially owns ~~115~~114,~~456~~856,091 shares of our common stock, of which (i) 104,783,897 shares are held by Mr. Youyou directly; ~~(ii)~~and 10,072,194 shares are held indirectly by Westline Enterprises Limited, a corporation 100% owned by Mr. Youyou~~; and (iii) Mr~~. Youyou presently directly holds exercisable options to acquire 600,000 shares of our Company’s common stock. Assuming the issuance of 600,000 shares of our Company’s common stock, pursuant to the exercise of Mr. Youyou’s presently exercisable options, Mr. Youyou would beneficially own 49.94% of our Company’s outstanding common stock. As of November 30, ~~2018~~2019, Mr. Youyou has ~~not exercised any of these currently outstanding options and without the exercise of Mr. Youyou’s outstanding options, Mr. Youyou has~~ a 49.81% ownership of our Company’s issued and outstanding common stock.

Director Independence

See the disclosure under Item 10 “Directors, Executive Officers and Corporate Governance” of this Annual Report on Form 10-K.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table is a summary of the fees billed to us by Turner, Stone & Company, L.L.P. (“Turner Stone”) for professional services for the fiscal years as disclosed in the table below:

Fee Category	Fees Billed in Fiscal ~~2018~~2019		Fees Billed in Fiscal ~~2017~~2018
Audit Fees	$	~~119~~40,~~505~~355	$	40119,~~720~~505
Audit-Related Fees		–		–
Tax Fees		–		–
All Other Fees		–		–
Total Fees	$	~~119~~40,~~505~~355	$	40119,~~720~~505

Audit Fees

Audit fees consist of fees for services billed by Turner Stone, which is a PCAOB registered independent auditor, for the audit and review of our consolidated financial statements.

Audit-Related Fees

None.

Tax Fees

None.

All Other Fees

None.

In addition, we were billed ~~tax~~$5,400 ~~fees~~ Cdn which consisted of fees billed by ~~Collins~~RSM ~~Barrow L.L.P.~~Canada, an independent third party, Canadian chartered accounting firm, relating to the preparation of our Company’s tax returns.

Audit Committee Pre-Approval Policies and Procedures

Provisionally our entire Board, which has a majority of independent directors, will act and fulfill the role of our audit committee.

Our Board of Directors, acting as the Audit Committee, engaged Turner Stone as our independent registered public accounting firm, effective ~~April~~January 307, ~~2018~~2019, to audit and render an opinion on our consolidated financial statements for the fiscal year ending September 30, ~~2018~~2019 and to review our quarterly consolidated financial statements for the periods ending December 31, ~~2017~~2018, March 31, ~~2018~~ 2019 and June 30, ~~2018~~2019. Our Board of Directors, acting as the Audit Committee, engaged Turner Stone as our independent registered public accounting firm, effective ~~March~~April 930, 2018, to audit and render an opinion on our consolidated financial statements for the fiscal year ending September 30, ~~2017~~2018 and to review our quarterly consolidated financial statements for the periods ending December 31, ~~2016~~ 2017, March 31, ~~2017~~2018 and June 30, ~~2017~~2018. Our Board of Directors, acting as the Audit Committee, pre-approved all audit and non-audit services provided by Turner Stone for the fiscal years ending September 30, ~~2018~~2019 and September 30, ~~2017~~2018. Further our Board of Directors, acting as the Audit Committee, considered the nature and amount of the fees billed by Turner Stone, and believes that the provision of the services for activities unrelated to the audit of our September 30, ~~2018~~2019 and September 30, ~~2017~~2018 financial statements is compatible with maintaining the independence of Turner Stone.

3547

PART IV

ITEM 15.

EXHIBITS, FINANCIAL STATEMENT SCHEDULES

Financial Statements filed with this Annual Report

The following listed financial statements and report of independent registered public accounting firm are filed as part of this Annual Report (see disclosure under Item 8 “Financial Statements and Supplementary Data” of this Annual Report for further information)

1. Consolidated Balance Sheets for September 30, ~~2018~~2019 and ~~2017~~2018.

2. Consolidated Statements of Operations for the years ended September 30, ~~2018~~2019 and ~~2017~~2018.

3. Consolidated Statements of Shareholders’ Equity for the period from September 30, ~~2018~~2019 to September 30, ~~2017~~2018.

4. Consolidated Statements of Cash Flows for the years ended September 30, ~~2018~~2019 and ~~2017~~2018.

Notes to the Consolidated Financial Statements.

Turner, Stone & Company, L.L.P. Report of Independent Registered Public Accounting Firm.

Financial Statement Schedules filed with this Annual Report

None.

Exhibits

The following Exhibits have been or are being filed herewith and are numbered in accordance with Item 601 of Regulation S-K:

Exhibit No.		Description
2.1		Liquidating Plan of Reorganization of Allied Devices Corporation, now known as Deep Well Oil & Gas, Inc. (incorporated by reference to Exhibit 2.1 to our Form 10-K/A filed on January 28, 2004).
2.2		Order and Plan of Reorganization of the U.S. Bankruptcy Court in and for the Eastern District of New York, In re: Allied Devices Corporation, Chapter 11, Case No. 03-80962-511, dated September 10, 2003 (incorporated by reference to Exhibit 2.2 to our Form 10-K/A filed on January 28, 2004).
3.1		Restated and Amended Articles of Incorporation filed with and accepted by the Secretary of State of Nevada on October 22, 2003, changing the name to “Deep Well Oil and Gas, Inc.” and otherwise implementing the Plan (incorporated by reference to Exhibit 3.1 to our Form 10-K/A filed on January 28, 2004).
3.2		Amended Articles of Incorporation filed with the State of Nevada on February 27, 2004, reflecting our two (2) shares for one (1) share forward stock split (incorporated by reference to Exhibit 3.1 to our Form 8-K filed on March 5, 2004).
3.3		Amended Articles of Incorporation filed with the State of Nevada on May 5, 2004, reflecting our three (3) shares for one (1) share forward stock split (incorporated by reference to Exhibit 3.2 to our Form 8-K filed on May 7, 2004).
3.4		Registrant’s By-laws, filed with Form 10-KSB on February 23, 2007 (incorporated by reference to Exhibit 3.4 to our Form 10-KSB filed on February 23, 2007).
3.5		Registrant’s Amended and Restated By-laws, filed with Form 8-K on September 3, 2009 (incorporated by reference to Exhibit 3.1 to our Form 8-K filed on September 3, 2009).
3.6		Amended Articles of Incorporation filed with the State of Nevada on May 15, 2013 and effective on May 24, 2013, increasing the aggregate number of shares which the Company has authority to issue from 300,000,000 common shares, with $0.001 par value per share, to 600,000,000 shares of common stock, with $0.001 par value per share (incorporated by reference to Exhibit 3.1 to our Form 8-K filed on May 17, 2013).
3.7		Registrant’s Amended and Restated By-laws, filed with Form 8-K on October 5, 2015 (incorporated by reference to Exhibit 3.1 to our Form 8-K filed on October 5, 2015).
4.1		Form of Warrant issued pursuant to a Subscription Agreement dated effective November 23, 2012 by and among our Company with one investor related to one Private Placement offering (incorporated by reference to Exhibit 4.2 to our Form 8-K filed on December 12, 2012).
4.2*		Form of Warrant issued pursuant to a Subscription Agreement dated July 10, 2013 by and among our Company with a consultant of our Company related to an Amending Agreement by and between Northern Alberta Oil Ltd. and Portwest Investments Ltd., dated July 10, 2013 (incorporated by reference to Exhibit 4.2 to our Form 8-K filed on July 17, 2013).
10.1*		Consulting agreement by and between Northern Alberta Oil Ltd. and Concorde Consulting, dated July 1, 2005 (incorporated by reference to Exhibit 10.17 to our Form 10-KSB filed on February 23, 2007).
10.2*		Deep Well Oil & Gas, Inc. Stock Option Plan, effective November 28, 2005 and amended December 4, 2013 (incorporated by reference to Exhibit 10.3 to our Form 10-K filed on January 13, 2015).
10.3		Sample Stock Option Agreement issued on March 23, 2011, to six directors (Mr. Said Arrata, Mr. Satya Brata Das, Mr. David Roff, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou) of the Company (incorporated by reference to Exhibit 10.4 to our Form 10-K filed on January 13, 2015).
10.4		Form of Subscription Agreement dated effective November 23, 2012 by and among our Company with one investor (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on December 12, 2012).
10.5		Form of Purchase and Sale Agreement effective December 3, 2012 by and among our Company and 1132559 Alberta Ltd. (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on December 17, 2012).
10.6		Sample Stock Option Agreement issued on June 20, 2013, to six directors (Mr. Said Arrata, Mr. Satya Brata Das, Mr. David Roff, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou) of the Company (incorporated by reference to Exhibit 10.7 to our Form 10-K filed on January 13, 2015).
10.7*		Stock Option Agreement issued on June 20, 2013, to Concorde Consulting (incorporated by reference to Exhibit 10.8 to our Form 10-K filed on January 13, 2015).
10.8*		Stock Option Agreement issued on June 20, 2013, to Portwest Investments Ltd. (incorporated by reference to Exhibit 10.9 to our Form 10-K filed on January 13, 2015).
10.9		Sample Stock Option Agreement issued on June 20, 2013, to one employee of the Company (incorporated by reference to Exhibit 10.10 to our Form 10-K filed on January 13, 2015).
10.10*		Form of Subscription Agreement dated July 10, 2013 by and among our Company with a consultant of our Company, related to an Amending Agreement by and between Northern Alberta Oil Ltd. and Portwest Investments Ltd., dated July 10, 2013 (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on July 17, 2013).

3748

10.11		Form of Subscription Agreement dated effective July 31, 2013 by and among our Company with one investor (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on August 5, 2013 and Exhibit 4.1 to our Form 8-K/A filed on October 15, 2013).
10.1*		Consulting agreement by and between Northern Alberta Oil Ltd. and Concorde Consulting, dated July 1, 2005 (incorporated by reference to Exhibit 10.17 to our Form 10-KSB filed on February 23, 2007).
10.12		Farmout Agreement between the Company and Farmee dated July 31, 2013 (incorporated by reference to Exhibit 10.1 to our Form 8-K/A filed on October 15, 2013).
10.2*		Deep Well Oil & Gas, Inc. Stock Option Plan, effective November 28, 2005 and amended December 4, 2013 (incorporated by reference to Exhibit 10.3 to our Form 10-K filed on January 13, 2015).
10.13		SAGD Demonstration Project Agreement dated July 30, 2013 between the Company and its joint venture partner (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on August 21, 2013).
10.3		Form of Purchase and Sale Agreement effective December 3, 2012 by and among our Company and 1132559 Alberta Ltd. (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on December 17, 2012).
10.14		Stock Option Agreement issued on October 28, 2013, to a contractor of the Company (incorporated by reference to Exhibit 10.16 to our Form 10-K filed on January 13, 2015).
10.4		Sample Stock Option Agreement issued on June 20, 2013, to six directors (Mr. Said Arrata, Mr. Satya Brata Das, Mr. David Roff, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou) of the Company (incorporated by reference to Exhibit 10.7 to our Form 10-K filed on January 13, 2015).
10.15		Stock Option Agreement issued on December 4, 2013, to a director (Mr. Pascal Node-Langlois) of the Company (incorporated by reference to Exhibit 10.17 to our Form 10-K filed on January 13, 2015).
10.5*		Stock Option Agreement issued on June 20, 2013, to Concorde Consulting (incorporated by reference to Exhibit 10.8 to our Form 10-K filed on January 13, 2015).
10.16		Acquisition of Royalty Interest Agreement dated March 18, 2014 between Northern Alberta Oil Ltd. and JV Partner (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on July 3, 2014).
10.6*		Stock Option Agreement issued on June 20, 2013, to Portwest Investments Ltd. (incorporated by reference to Exhibit 10.8 to our Form 10-K filed on January 13, 2015).
10.17		General Indenture of Conveyance, Assignment and Transfer Agreement dated March 18, 2014 between Northern Alberta Oil Ltd. and JV Partner (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on July 3, 2014).
10.7		Sample Stock Option Agreement issued on June 20, 2013, to one employee of the Company (incorporated by reference to Exhibit 10.10 to our Form 10-K filed on January 13, 2015).
10.18		Acquisition of Royalty Interest Agreement dated June 16, 2014 between Northern Alberta Oil Ltd. and Mr. Malik Youyou (incorporated by reference to Exhibit 10.3 to our Form 8-K filed on July 3, 2014).
10.8*		Form of Subscription Agreement dated July 10, 2013 by and among our Company with a consultant of our Company, related to an Amending Agreement by and between Northern Alberta Oil Ltd. and Portwest Investments Ltd., dated July 10, 2013 (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on July 17, 2013).
10.19		General Indenture of Conveyance, Assignment and Transfer Agreement dated June16, 2014 between Northern Alberta Oil Ltd. and Mr. Malik Youyou (incorporated by reference to Exhibit 10.4 to our Form 8-K filed on July 3, 2014).
10.9		Farmout Agreement between the Company and Farmee dated July 31, 2013 (incorporated by reference to Exhibit 10.1 to our Form 8-K/A filed on October 15, 2013).
10.20		Sample Stock Option Agreement issued on September 19, 2014, to seven directors (Mr. Said Arrata, Mr. Satya Brata Das, Mr. Pascal Node-Langlois, Mr. David Roff, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou) of the Company (incorporated by reference to Exhibit 10.22 to our Form 10-K filed on January 13, 2015).
10.10		SAGD Demonstration Project Agreement dated July 30, 2013 between the Company and its joint venture partner (incorporated by reference to Exhibit 4.1 to our Form 8-K filed on August 21, 2013).
10.21*		Sample Stock Option Agreement issued on September 19, 2014, to Concorde Consulting (incorporated by reference to Exhibit 10.23 to our Form 10-K filed on January 13, 2015).
10.11		Stock Option Agreement issued on October 28, 2013, to a contractor of the Company (incorporated by reference to Exhibit 10.16 to our Form 10-K filed on January 13, 2015).
10.22*		Sample Stock Option Agreement issued on September 19, 2014, to Portwest Investments Ltd. (incorporated by reference to Exhibit 10.24 to our Form 10-K filed on January 13, 2015).
10.12		Stock Option Agreement issued on December 4, 2013, to a director (Mr. Pascal Node-Langlois) of the Company (incorporated by reference to Exhibit 10.17 to our Form 10-K filed on January 13, 2015).
10.23		Sample Stock Option Agreement issued on September 19, 2014, to one employee of the Company (incorporated by reference to Exhibit 10.25 to our Form 10-K filed on January 13, 2015).
10.13		Acquisition of Royalty Interest Agreement dated March 18, 2014 between Northern Alberta Oil Ltd. and JV Partner (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on July 3, 2014).
10.24		Sample Indemnity Agreement with all directors of the Company (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on September 25, 2014).
10.14		General Indenture of Conveyance, Assignment and Transfer Agreement dated March 18, 2014 between Northern Alberta Oil Ltd. and JV Partner (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on July 3, 2014).
10.25		Stock Option Agreement issued on November 17, 2014, to a director (Mr. Colin Outtrim) of the Company (incorporated by reference to Exhibit 10.27 to our Form 10-K filed on January 13, 2015).
10.15		Acquisition of Royalty Interest Agreement dated June 16, 2014 between Northern Alberta Oil Ltd. and Mr. Malik Youyou (incorporated by reference to Exhibit 10.3 to our Form 8-K filed on July 3, 2014).
10.26		Farmout Amending Agreement dated November 17, 2014 (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on November 21, 2014).
10.16		General Indenture of Conveyance, Assignment and Transfer Agreement dated June16, 2014 between Northern Alberta Oil Ltd. and Mr. Malik Youyou (incorporated by reference to Exhibit 10.4 to our Form 8-K filed on July 3, 2014).
10.17		Sample Stock Option Agreement issued on September 19, 2014, to seven directors (Mr. Said Arrata, Mr. Satya Brata Das, Mr. Pascal Node-Langlois, Mr. David Roff, Dr. Horst A. Schmid, Mr. Curtis Sparrow and Mr. Malik Youyou) of the Company (incorporated by reference to Exhibit 10.22 to our Form 10-K filed on January 13, 2015).
10.18*		Sample Stock Option Agreement issued on September 19, 2014, to Concorde Consulting (incorporated by reference to Exhibit 10.23 to our Form 10-K filed on January 13, 2015).
10.19*		Sample Stock Option Agreement issued on September 19, 2014, to Portwest Investments Ltd. (incorporated by reference to Exhibit 10.24 to our Form 10-K filed on January 13, 2015).
10.20		Sample Stock Option Agreement issued on September 19, 2014, to one employee of the Company (incorporated by reference to Exhibit 10.25 to our Form 10-K filed on January 13, 2015).
10.21		Sample Indemnity Agreement with all directors of the Company (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on September 25, 2014).
10.22		Stock Option Agreement issued on November 17, 2014, to a director (Mr. Colin Outtrim) of the Company (incorporated by reference to Exhibit 10.27 to our Form 10-K filed on January 13, 2015).
14.1		Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 to our Form 10-K filed on January 13, 2015).
16.1		Letter from Sadler Gibb to the Securities and Exchange Commission, dated July 18, 2017 (incorporated by reference to Exhibit 16.1 to our Form 8-K filed on July 20, 2017)
18.1		Preferability Letter of Turner, Stone & Company, LLP (incorporated by reference to Exhibit 18.1 to our Form 10-K filed on December 29, 2017).
21.1		Subsidiaries of Registrant.
23.1		Consent of DeGolyer and MacNaughton Canada Limited, independent petroleum engineers (incorporated by reference to Exhibit 23.1 to our Form 10-K filed on January 13, 2015).
23.2		Consent of DeGolyer and MacNaughton Canada Limited, independent petroleum engineers (incorporated by reference to Exhibit 23.2 to our Form 10-K filed on December 29, 2017).
31.1		Certification of President and Chief Executive Officer pursuant to Rule 13a-14(a).
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a).
32.1		Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
99.1		Insider Trading Policy (incorporated by reference to Exhibit 99.1 to our Form 10-K filed on January 13, 2015).
99.2		Amended Insider Trading Policy (incorporated by reference to Exhibit 99.2 to our Form 10-K filed on December 29, 2017).
99.3		Audit Committee Whistle-Blower Policy (incorporated by reference to Exhibit 99.2 to our Form 10-K filed on January 13, 2015).
99.4		Audit Committee Charter (incorporated by reference to Exhibit 99.3 to our Form 10-K filed on January 13, 2015).
99.5		Compensation Committee Charter (incorporated by reference to Exhibit 99.4 to our Form 10-K filed on January 13, 2015).
99.6		Corporate Governance and Nominating Committee Charter (incorporated by reference to Exhibit 99.5 to our Form 10-K filed on January 13, 2015).
99.7		Reserves and Resources Committee Charter (incorporated by reference to Exhibit 99.6 to our Form 10-K filed on January 13, 2015).
101		Interactive Data Files

Management contract or compensatory plan or arrangement.

ITEM 16.

FORM 10-K SUMMARY

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DEEP WELL OIL & GAS, INC.
	By	/s/ Horst A. Schmid
		Dr. Horst A. Schmid
		Chairman of the Board
	Date	~~December~~January 2113, ~~2018~~2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By /s/ Horst A. Schmid Dr. Horst A. Schmid Chief Executive Officer and President (Principal Executive Officer) Date ~~December~~January 2113, ~~2018~~2020 By /s/ Curtis ~~James~~J. Sparrow Mr. Curtis James Sparrow Chief Financial Officer (Principal Financial Officer) Date ~~December~~January 2113, ~~2018~~2020

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