UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended ~~June 30~~December 31, 2019

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

For the transition period from ________to________

Commission file number 0-24012

DEEP WELL OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

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

Former name, former address and former fiscal year, if changed since last report: not applicable.

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit files). Yes þ No o☐

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

Large accelerated filer o☐ Accelerated filer o☐ Non-accelerated filer o☐ 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. o☐

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

As of the date of filing this quarterly report on Form 10-Q with the U.S. Securities and Exchange Commission (the “SEC”), Deep Well Oil & Gas, Inc. had outstanding 230,574,603 shares of common stock.

TABLE OF CONTENTS

		Page Number
PART I – FINANCIAL INFORMATION
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)	1
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1110
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	1817
ITEM 4.	CONTROLS AND PROCEDURES	1817
PART II – OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	1918
ITEM 1A.	RISK FACTORS	1918
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	19
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	19
ITEM 4.	MINE SAFETY DISCLOSURES	19
ITEM 5.	OTHER INFORMATION	19
ITEM 6.	EXHIBITS	2019
SIGNATURES		2120

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

Condensed Consolidated Balance Sheets

~~June~~December 3031, 2019 and September 30, ~~2018~~2019

	June 30,			September 30,
	December 31, 2019			September 30,
	2019			2018
	(Unaudited)			2019
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	3437,~~364~~706		$	~~298~~49,~~241~~715
Accounts receivable		8870,~~415~~368			4083,~~920~~398
Prepaid expenses		4039,~~615~~423			2434,~~730~~266
Total Current Assets		~~163~~147,~~394~~497			~~363~~167,~~891~~379
Long term investments		~~399~~406,~~498~~576			~~398~~396,~~055~~782
Oil and gas properties, net, based on full cost method of accounting		22,036,030			21,975,868
Unproved Oil and gas properties, net, based on full cost method of accounting		22,047,866			22,040,307
Property and equipment, net		7770,~~651~~146			8973,~~518~~509
TOTAL ASSETS	$	22,~~676~~672,~~573~~085		$	22,~~827~~677,~~332~~977
LIABILITIES
Current Liabilities
Accounts payable and accrued liabilities	$	2491,~~379~~739		$	4569,~~137~~617
Accounts payable and accrued liabilities – related parties		~~1,210~~–			–1,375
Total Current Liabilities		2591,~~589~~739			4570,~~137~~992
Asset retirement obligations (Note 7)		~~501~~514,~~793~~970			~~493~~500,~~467~~392
TOTAL LIABILITIES		~~527~~606,~~382~~709			~~538~~571,~~604~~384
Commitments and contingencies (Note 11)
(Commitments and contingencies Note 11)
SHAREHOLDERS’ EQUITY
Common Stock: (Note 8)
Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 230,574,603 shares (September 30, 2018 – 230,574,603 shares)		230,574			230,574
Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 230,574,603 shares (September 30, 2019 – 230,574,603 shares)		230,574			230,574
Additional paid in capital		43,104,276			43,104,276
Subscriptions receivable – related party					(15,000	)
Accumulated deficit		(21,269,474	)		(21,228,257	)
Accumulated deficit		(21,185,659	)		(21,031,122	)
Total Shareholders’ Equity		22,065,376			22,106,593
Total Shareholders’ Equity		22,149,191			22,288,728
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	22,672,085		$	22,677,977
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	22,676,573		$	22,827,332

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Condensed Consolidated Statements of Operations ~~and Comprehensive Loss~~

For ~~the~~ Three ~~and Nine~~ Months Ended ~~June 30~~December 31, 2019 and 2018

	Three Months Ended			Three Months Ended			Nine Months Ended			Nine Months Ended
	December 31,			December 31,
	June 30,			June 30,			June 30,			June 30,
	2019			2018
	2019			2018			2019			2018
Revenue	$	–		$	–
Revenue	$	–		$	–		$	–		$	–
Royalty refunds (expenses)		–			–
Royalty refunds (expenses)		–			–			–			–
Revenue, net of royalty		–			–
Revenue, net of royalty		–			–			–			–
Expenses
Expenses
Operating expenses		27,738			39,660
Operating expenses		16,256			65,367			59,736			130,924
Operating expenses covered by Farmout		(27,738	)		(39,660	)
Operating expenses covered by Farmout		(16,256	)		(65,367	)		(59,736	)		(130,924	)
General and administrative		30,321			53,855
General and administrative		35,852			61,657			129,273			236,522
Depreciation, accretion and depletion		10,843			11,442
Depreciation, accretion and depletion		11,384			12,956			34,237			39,031
Net loss from operations		(41,164	)		(65,297	)
Net loss from operations		(47,236	)		(74,613	)		(163,510	)		(275,553	)
Other income and expenses
Other income and expenses
Rental and other income		(2,047	)		2,046
Rental and other income		1,210			(39	)		3,276			8,825
Interest income		1,994			1,810
Interest income		1,964			1,526			5,697			4,427
Net loss	$	(41,217	)	$	(61,441	)
Net loss and comprehensive loss	$	(44,062	)	$	(73,126	)	$	(154,537	)	$	(262,301	)
Net loss per common share
Net loss per common share
Basic and Diluted	$	(0.00	)	$	(0.00	)
Basic and Diluted	$	(0.00	)	$	(0.00	)	$	(0.00	)	$	(0.00	)
Weighted Average Outstanding Shares (in thousands)
Weighted Average Outstanding Shares (in thousands)
Basic and Diluted		230,574			230,574
Basic and Diluted		230,574			229,608			230,574			229,452

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Condensed Consolidated Statements of Changes in Shareholders’ Equity

For the Three ~~and Nine~~ Months Ended ~~June 30,~~December 31, 2019 and 2018

	Common Shares				Additional Paid in		Subscription			Accumulated
	Shares		Amount		Capital		Receivable			Deficit			Total
FOR THE NINE MONTHS ENDED JUNE 30, 2018
For the Three Months Ended December 31, 2018
Balance at September 30, 2017		229,374,605	$	229,374	$	42,845,292	$	–		$	(20,700,991	)	$	22,373,675
Net operating loss for the quarter ended December 31, 2017		–		–		–		–			(129,135	)		(129,135	)
Balance at December 31, 2017		229,374,605	$	229,374	$	42,845,292	$	–		$	(20,830,126	)	$	22,244,540
Net operating loss for the quarter ended March 31, 2018		–		–		–		–			(60,040	)		(60,040	)
Balance at March 31, 2018		229,374,605	$	229,374	$	42,845,292	$	–		$	(20,890,166	)	$	22,184,500
Options exercised, June 2018		1,199,998		1,200		13,800		–			–			15,000
Subscription receivable		–		–		–		(15,000	)		–			(15,000	)
Distribution refund		–		–		243,574		–			–			243,574
Net operating loss for the quarter ended June 30, 2018		–		–		–		–			(73,126	)		(73,126	)
Balance at June 30, 2018		230,574,603	$	230,574	$	43,102,666	$	(15,000	)	$	(20,963,292	)	$	22,354,948
FOR THE NINE MONTHS ENDED JUNE 30, 2019
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 operating loss for the quarter ended December 31, 2018		–		–		–		–			(61,441	)		(61,441	)
Net loss for the quarter ended December 31, 2018		–		–		–		–			(61,441	)		(61,441	)
Balance at December 31, 2018		230,574,603	$	230,574	$	43,104,276	$	–		$	(21,092,563	)	$	22,242,287
Net operating loss for the quarter ended March 31, 2019		–		–		–		–			(49,034	)		(49,034	)
For the Three Months Ended December 31, 2019
Balance at March 31, 2019		230,574,603	$	230,574	$	43,104,276	$	–		$	(21,141,597	)	$	22,193,253
Balance at September 30, 2019		230,574,603	$	230,574	$	43,104,276	$	–		$	(21,228,257	)	$	22,106,593
Net operating loss for the quarter ended June 30, 2019		–		–		–		–			(44,062	)		(44,062	)
Net loss for the quarter ended December 31, 2019		–		–		–		–			(41,217	)		(41,217	)
Balance at June 30, 2019		230,574,603	$	230,574	$	43,104,276	$	–		$	(21,185,659	)	$	22,149,191
Balance at December 31, 2019		230,574,603	$	230,574	$	43,104,276	$	–		$	(21,269,474	)	$	22,065,376

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Condensed Consolidated Statements of Cash Flows

For the ~~Nine~~Three ~~months~~Months ~~ended~~Ended ~~June~~December 3031, ~~2019~~ 2019 and 2018

	June 30,			June 30,
	December 31,			December 31,
	2019			2018
CASH PROVIDED BY (USED IN):
Operating Activities
Net loss	$	(~~154~~41,~~537~~217	)	$	(~~262~~61,~~301~~441	)
Items not affecting cash:
Depreciation, accretion and depletion		3410,~~237~~843			3911,~~031~~442
Net changes in non-cash working capital (Note 10)		~~(82~~28,~~928~~620	)		(8631,~~126~~856	)
Net Cash Used in Operating Activities		(~~203~~1,~~228~~754	)		(~~309~~81,~~396~~855	)
Investing Activities
Purchase of equipment		~~(534~~–	)		–(534	)
Investment in oil and gas properties		(8012,~~886~~272	)		(~~596~~50,~~930~~904	)
Long term investments		52,~~771~~017			31,~~955~~743
Net Cash Used in Investing Activities		(7510,~~649~~255	)		(~~592~~49,~~975~~695	)
Financing Activities
Subscription receivable collected		~~15,000~~–			–15,000
Distribution refund		–			243,574
Net Cash Provided by Financing Activities		–			15,000
Net Cash Provided by Financing Activities		15,000			243,574
Decrease in cash and cash equivalents		(12,009	)		(116,550	)
Decrease in cash and cash equivalents		(263,877	)		(658,797	)
Cash and cash equivalents, beginning of period		49,715			298,241
Cash and cash equivalents, beginning of period		298,241			1,097,651
Cash and cash equivalents, end of period	$	37,706		$	181,691
Cash and cash equivalents, end of period	$	34,364		$	438,854
Supplemental Cash Flow Information:
Cash paid for interest	$	–		$	–
Cash paid for income taxes	$	–		$	–

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Notes to the Condensed Consolidated Financial Statements

~~June~~December 3031, 2019

NATURE OF BUSINESS AND BASIS OF PRESENTATION

Nature of Business

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

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

Basis of Presentation

The interim condensed consolidated financial statements included herein have been prepared by the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate so as to make the information presented not misleading.

These interim condensed consolidated financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated financial statements for the year ended September 30, ~~2018~~2019.

These statements reflect all adjustments, consisting solely of normal recurring adjustments (unless otherwise disclosed) which, in the opinion of management, are necessary for a fair presentation of the information contained therein. However, the results of operations for the interim periods may not be indicative of results to be expected for the full fiscal year. It is suggested that these condensed consolidated financial statements be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended September 30, ~~2018~~2019.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

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

Crude oil and natural gas properties

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

Under the full cost method, oil and gas properties are subject to the ceiling test performed quarterly. A ceiling test write-down is recognized in net earnings if the carrying amount of a cost centre exceeds the “cost centre ceiling”. The carrying amount of the cost centre includes the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes. The cost centre ceiling is the sum of (A) present value of the estimated future net cash flows from proved oil and natural gas reserves using a 10 percent per year discount factor, (B) the costs of unproved properties not being amortized, and (C) the lower of cost or fair value of unproved properties included in the costs being amortized; less (D) related income tax effects. As of ~~June~~December 3031, 2019, no ceiling test write-downs were recorded for the Company’s 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.

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 ~~June~~December 3031, 2019, and September 30, ~~2018~~2019, asset retirement obligations amount to $~~501~~514,~~793 and~~970 and $~~493~~500,~~467~~392, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the ~~government~~ government estimates the cost of abandonment and reclamation to be.

Foreign Currency Translation

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

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 ~~June~~December 3031, 2019, the Company has approximately $719,~~385~~458 funds that are in excess of deposit insurance limits, which may have financial credit risk. For the Company funds that are maintained in a financial institution which has its deposits fully guaranteed by CUDGC, there is no financial credit risk.

The Company is not directly subject to credit risk resulting from the concentration of its crude oil sales. For the period ending ~~June~~December 3031, 2019 and December 31, 2018 the Company recorded no oil sales.

Basic and Diluted Net Loss Per Share

Basic net loss per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net loss per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were ~~7,380,000~~no potentially dilutive securities excluded from the the diluted earnings per share calculation ~~because~~ because their effect would be antidilutive.

Recently Adopted Accounting Standards

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous U.S. GAAP. The guidance is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. This ASU does not apply to the Company’s oil sand leases. ~~It may affect the equipment leases.~~ The adoption of this standard isdid not ~~expected to~~ have a material impact on the Company’s consolidated financial statements because the Company has no leases that the new accounting standard applies to.

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.

OIL AND GAS PROPERTIES

The Company’s oil sands acreage as of ~~June~~December 3031, 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 its oil sands leases “into perpetuity”, based on the Alberta governmental regulations, the~~ lease expiration dates of the Company’s ~~nine~~ oil sands leases are as follows:

1. 14Out of 20,~~549~~242 gross acres (813,~~571~~284 net acres) under five oil sands leases that were set to expiry on July 10, 2018, ~~and~~14,549 ~~were~~gross ~~subsequently~~acres (8,571 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. In November of 2017, the Company’s joint venture partner and operator of two of the five oil sands leases, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue 7,591 gross acres (1,898 net acres) and in January 2018, approval was received from Alberta Energy to continue 6,958 gross acres (1,740 net acres). In June 2018, the Company as operator of three of these five oil sands leases, submitted three continuation applications to the Alberta Oil Sands Tenure division to apply to continue another 7,591 gross acres (6,832 net acres) where resources were identified and in July 2018 and April 2019, approval was received from Alberta Energy to continue 7,591 gross acres (6,832 net acres). Of these five oil sands leases that were set to expiry on July 10, 2018, a total of 5,693 gross acres (4,713 net acres) expired without being continued. These expired lands were primarily areas where the Company determined that there was no or limited exploitable resources. These continued leases ~~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;

2. 19,610 gross acres (17,649 net acres) under three northern oil sands leases are set to expire on August 19, 2019. The Company applied for a term extension on these three northern oil sands leases, however it is not certain if an extension will be granted by Alberta Energy; and6

32. 3Out of 19,~~163~~610 gross acres (317,~~163~~649 net acres) under ~~one~~the three most northern oil sands ~~lease~~leases ~~are~~that were set to expire on ~~April~~August 919, ~~2024~~2019, 1,898 gross acres (1,708 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and have no set expiry date. ItIn isAugust 2019, the Company’s ~~opinion~~as ~~that~~operator ~~they~~of ~~have~~these ~~already~~three ~~met~~most northern leases submitted one continuation application to the ~~governmental~~Alberta ~~requirements~~Oil ~~for~~Sands ~~this~~Tenure ~~lease~~division to apply to continue 1,898 gross acres (1,708 net acres) and ~~they~~in ~~will~~October be2019, ~~applying~~approval was received from Alberta Energy to continue ~~this~~1,898 gross acres (1,708 net acres). Of these three most northern oil sands leases that were set to expiry on August 19, 2019, a total of 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where the Company determined that there was no or limited exploitable resources. This one partially continued lease ~~into~~is now held by the Company for perpetuity., subject to yearly escalating rental payments until the lease is deemed to be a producing lease; and

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

Lease Rental Commitments

The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The lease terms include certain commitments related to oil sands properties that require the payments of yearly rents. As required by the Oil Sands Tenure Regulation of the Mines and Minerals Act of Alberta continued oil sands leases past their expiry dates are subject to escalating rental payments in respect of each term year of a continued lease that is designated as non-producing less any eligible research costs, exploration costs and development costs that are incurred in the term year of a continued lease. Escalating rent is payable at the end of each term year, while annual rent for leases are due at the beginning of each term year. Lessees of continued oil sands leases may reduce or eliminate their escalating rent obligations by conducting exploration or development work, or research, on the non-producing lease. As of ~~June~~December 3031, 2019, excluding any eligible research, exploration and or development costs that may be used to reduce ~~the~~ the Company’s yearly escalating future rents, the following table sets out the estimated net payments due under this commitment, which could be as high:

	(USD $)		(Cdn $)
2019	$	11,125		14,559
2020	$	20,598	$	26,754
2020	$	20,648		27,022
2021	$	23,228	$	30,170
2021	$	19,621		25,678
2022	$	30,204	$	39,230
2022	$	26,543		34,738
2023	$	31,800	$	41,303
2023	$	23,376		30,592
2024	$	27,425	$	35,621
Subsequent	$	~~126~~153,~~122~~209	$	~~165~~198,~~058~~998

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

~~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 period ended ~~June 30~~December 31, 2019.

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

~~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.

CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES

The following table illustrates capitalized costs relating to oil producing activities for the ~~nine~~three months ended ~~June~~December 3031, 2019 and the fiscal year ended September 30, ~~2018~~2019:

	June 30, 2019			September 30, 2018
	December 31, 2019			September 30, 2019
Unproved Oil and Gas Properties	$	22,~~140~~157,~~305~~718		$	22,~~071~~147,~~787~~367
Accumulated Depreciation and Depletion		(~~104~~109,~~275~~852	)		(95107,~~919~~060	)
Net Capitalized Cost	$	22,~~036~~047,~~030~~866		$	2122,~~975~~040,~~868~~307

Depreciation and depletion expense for the ~~nine~~three months ended ~~June~~December 3031, 2019 and 2018 were $82,~~356~~785 and $82,~~356~~785 respectively.

EXPLORATION ACTIVITIES

The following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the ~~nine~~three months ended ~~June~~December 3031, 2019 and the fiscal year ended September 30, ~~2018~~2019:

	June 30, 2019		September 30, 2018
	December 31, 2019		September 30, 2019
Acquisition of Properties:
Proved	$	–	$	–
Unproved	$	–	$	~~38,185~~–
Exploration costs	$	6810,~~518~~351	$	~~710~~75,~~012~~580
Development costs	$	–	$	–

SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES

Accounts payable – related parties were $~~1,210~~Nil as of ~~June~~December 3031, 2019 (September 30, ~~2018~~2019 - $~~Nil~~1,375) for expenses to be reimbursed to directors. This amount is is unsecured, non-interest bearing, and has no fixed terms of repayment.

~~Subscriptions~~As ~~receivable – related parties was $Nil as~~ of ~~June~~December 3031, 2019, ~~(September 30~~officers, directors, ~~2018~~their ~~- $15~~families,~~000)~~ ~~for~~and ~~the~~their ~~amount~~controlled ~~owed~~entities tohave ~~the~~acquired ~~Company~~53.96% ~~from~~of ~~one director for~~ the ~~exercise~~Company’s ofoutstanding ~~his~~common capital stock ~~options~~.

AsThe ofCompany ~~June~~incurred 30expenses $34,092 ~~2019,~~to ~~officers~~one related party, ~~directors,~~ ~~their~~Concorde ~~families~~Consulting, ~~and~~an ~~their~~entity controlled ~~entities~~by ~~have~~a ~~acquired~~director, ~~53.96%~~for ofprofessional fees and consulting services provided to the Company’s ~~outstanding~~during ~~common~~the ~~capital stock.~~period ~~This~~ended ~~percentage~~December ~~does~~31, ~~not~~2019 ~~include~~(December ~~unexercised~~31, ~~warrants~~2018 or- ~~stock~~$34,088). ~~options~~These amounts were fully paid as of December 31, 2019.

The Company incurred expenses $101,574 to one related party, Concorde Consulting, and entity controlled by a director, for professional fees and consulting services provided to the Company during the period ended June 30, 2019 (June 30, 2018 - $105,840). These amounts were fully paid as of June 30, 2019.

ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At ~~June~~December 3031, 2019, the Company estimates the undiscounted cash flows related to asset ~~retirement~~ ~~obligation~~retirement obligations to total approximately $~~617~~622,~~565~~253 (September 30, ~~2018~~2019 - $~~624~~610,~~354~~291). The fair value of the liability at ~~June 30~~December 31, 2019 is estimated to be $~~501~~514,~~793~~970 (September 30, ~~2018~~2019 - $~~493~~500,~~467~~392) using a risk-free rate of 3.74% and an inflation rate of 2%. The actual costs to settle the obligation are expected to occur in approximately 2423 years.

Changes to the asset retirement obligation were as follows:

	June 30, 2019			September 30, 2018
	December 31, 2019			September 30, 2019
Balance, beginning of period	$	~~493~~500,~~467~~392		$	493,~~411~~467
Liabilities incurred		–			–
Effect of foreign exchange		(59,~~156~~884	)		(1711,~~893~~081	)
Disposal		–			–
Accretion expense		134,~~482~~694			1718,~~949~~006
Balance, end of period	$	~~501~~514,~~793~~970		$	~~493~~500,~~467~~392

COMMON STOCK

Common Stock Issued and Outstanding

As of ~~June~~December 3031, 2019, the ~~Company~~ Company had outstanding 230,574,603 shares of common stock.

STOCK OPTIONS

~~Between~~On ~~June~~November ~~8 to 10~~17, ~~2018~~2019, ~~five directors~~600, ~~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 ofoptions ~~$0.07~~previously ~~per~~granted ~~share~~ on ~~June~~November 817, ~~2018,~~2014 ~~whereby 2,250,002 common shares were withheld by the Company~~ to ~~pay~~one ~~for~~director ~~the~~expired ~~exercise price of the options~~unexercised. ~~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.~~

OnThe ~~June~~following ~~19,~~is ~~2018,~~a ~~one~~summary ~~director~~ of ~~the Company acquired 300,000 common shares of the Company upon exercising~~ stock ~~options,~~option ~~at an exercise price of $0.05 per common~~activity ~~share~~as ~~for~~at ~~total~~December ~~gross proceeds to the Company of $15~~31,~~000.~~ 2019:

On October 28, 2018, 250,000 stock options previously granted on October 28, 2013 to a contractor for services in connection with the Farmout Agreement, expired unexercised.

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

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

Expired, November 17, 2019		(600,000	)		0.23		0.18
Balance, December 31, 2019		–		$	–	$	–

Exercisable, December 31, 2019		–		$	–	$	–

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

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

	Shares Underlying Options Outstanding						Shares Underlying Options Exercisable
Range of Exercise Price	Shares Underlying Options Outstanding		Weighted Average Remaining Contractual Life		Weighted Average Exercise Price		Shares Underlying Options Exercisable		Weighted Average Exercise Price
$0.38 at June 30, 2019		6,780,000		0.22	$	0.38		6,780,000	$	0.38
$0.23 at June 30, 2019		600,000		0.38	$	0.23		600,000	$	0.23
		7,380,000		0.24	$	0.37		7,380,000	$	0.37

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

The following is a summary of stock option activity as at June 30, 2019:

	Number of Underlying Shares			Weighted Average Exercise Price		Weighted Average Fair Market Value
Balance, September 30, 2018		8,080,000		$	0.36	$	0.29
Expired, October 28, 2018		(250,000	)		0.30		0.30
Expired, December 4, 2018		(450,000	)		0.34		0.36
Balance, June 30, 2019		7,380,000		$	0.37	$	0.29
Exercisable, June 30, 2019		7,380,000		$	0.37	$	0.29

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

10.

CHANGES IN NON-CASH WORKING CAPITAL

	Nine months ended			Nine months ended
	Three months ended			Three months Ended
	June 30, 2019			June 30, 2018
	December 31, 2019			December 31, 2018
Accounts receivable	$	~~(47~~13,~~495~~030	)	$	(1340,~~728~~607	)
Prepaid expenses		(155,~~885~~157	)		64,~~243~~835
Accounts payable		~~(19~~20,~~548~~747	)		~~(78~~3,~~641~~916	)
	$	~~(82~~28,~~928~~620	)	$	(8631,~~126~~856	)

11.

COMMITMENTS

Compensation to Executive Officers

Concorde Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for $11,~~286~~364 per month (Cdn $15,000 per month). As of ~~June~~December 3031, 2019, the Company did not owe Concorde Consulting any of this amount.

10Office Lease

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

12.

LEGAL ACTIONS

On October 28, 2019, Provident Premier Master Fund Ltd. (the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”) in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim had been filed on November 1, 2018 but the Company states that it had never been served so the Company was not aware of it. The Plaintiff claims that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all petroleum substances produced, saved and marketed from six of the Company’s oil sands leases located within the Company’s Sawn Lake properties. The Plaintiff seeks: 1) A declaration that the Plaintiff is the legal owner of 0.67% of the GORR payable on all oil sands produced from the lands which is payable by one or more of the Defendants; 2) An accounting to determine the amount of the outstanding royalty of which judgment is estimated by the Plaintiff to be in the amount of $100,000 Cdn; and 3) Interest and costs.

The Company continues to deny the validity of the Purported 6.5% Royalty in the first instance. As well, if the Purported 6.5% Royalty was valid, which is denied, it was not a gross overriding interest, but rather an overriding interest, which allowed for the deduction of operating and marketing costs. The Company plans to vigorously defend itself against the Plaintiff’s claims. As at December 31, 2019, no contingent liability has been recorded, as a successful outcome for the Plaintiff is not probable.

ITEM 2.

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

The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes. For the purpose of this discussion, unless the context indicates another meaning, the terms: “Deep Well,” “Company,” “we,” “us,” and “our” refer to Deep Well Oil & Gas, Inc. and its subsidiaries. This discussion includes forward-looking statements that reflect our current views with respect to future events and financial performance that involve risks and uncertainties. Our actual results, performance or achievements could differ materially from those anticipated in the forward-looking statements as a result of certain factors including risks discussed in “Cautionary Note Regarding – Forward-Looking Statements” below and elsewhere in this report, and under the heading “Risk Factors” and “Environmental Laws and Regulations” disclosed in our Annual Report on Form 10-K for the fiscal year ended September 30, ~~2018~~2019, filed with the ~~Alberta~~U.S. Securities and Exchange Commission (“~~ASC~~SEC”) ~~on SEDAR on April 12, 2019~~ and the ~~U.S.~~Alberta Securities ~~and Exchange~~ Commission (“~~SEC~~ASC”) on SEDAR on ~~December 21~~January 13, ~~2018~~2020. Our Annual Report on Form 10-K can be downloaded from our website at www.deepwelloil.com.

Our consolidated financial statements and the supplemental information thereto are reported in United States dollars and are prepared based upon United States generally accepted accounting principles (“US GAAP”). References in this quarterly report on Form 10-Q to “$” are to United States (“US”) dollars and references to “Cdn$” are to Canadian dollars. The following table sets forth the rates of exchange for the Cdn$, expressed in US dollars, in effect at the end of the following periods and the average rates of exchange during such periods, based on the rates of exchange for such periods as reported by the Bank of Canada.

Period Ending June 30	2019		2018
Period Ending December 31	2019		2018
Rate at end of period	$	0.~~7641~~7699	$	0.~~7594~~7330
Average rate for the three month period	$	0.~~7476~~7576	$	0.~~7747~~7575

General Overview

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

~~Results of Operations~~10

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:

	Three Months Ended			Three Months Ended			Nine Months Ended			Nine Months Ended
	June 30, 2019			June 30, 2018			June 30, 2019			June 30, 2018
Revenue	$	–		$	–		$	–		$	–
Royalty refunds (expenses)		–			–			–			–
Revenue, net of royalty		–			–			–			–
Expenses
Operating expenses		16,256			65,367			59,736			130,924
Operating expense covered by Farmout		(16,256	)		(65,367	)		(59,736	)		(130,924	)
General and administrative		35,852			61,657			129,273			236,522
Depreciation, accretion and depletion		11,384			12,956			34,237			39,031
Net loss from operations		(47,236	)		(74,613	)		(163,510	)		(275,553	)
Other income and expenses
Rental and other income		1,210			(39	)		3,276			8,825
Interest income		1,964			1,526			5,697			4,427
Net loss and comprehensive loss	$	(44,062	)	$	(73,126	)	$	(154,537	)	$	(262,301	)

First production from our present joint Steam Assisted Gravity Drainage Demonstration Project (the “SAGD Project”) began on September 16, 2014. A majority of our 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 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 we had a working interest of 50%. 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. 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 Project agreement entered into between us 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 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 June 30, 2019, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $20.8 million ($27.2 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 with the monthly shut-in operations of the SAGD Project facility.

For the three months ended June 30, 2019, our general and administrative expenses decreased by $25,805 compared to the three months ended June 30, 2018, which was primarily due to decreases of engineering fees and audit fees. We also received $90,000 during this quarter from the Farmee in accordance with a Farmout Agreement to offset our monthly expenses. After adjusting out the non-cash item foreign exchange loss, and the funds we received from the Farmee, our general and administrative expenses were $124,258 for the three months ended June 30, 2019 compared to $154,414 for the three months ended June 30, 2018.

For the nine months ended June 30, 2019, our general and administrative expenses decreased by $107,249 compared to the nine months ended June 30, 2018, which was primarily due to a decrease of engineering fees of $57,206 and a decrease of audit fees of $31,000. We also received $270,000 during the last nine months from the Farmee in accordance with the Farmout Agreement, to offset 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 $395,741 for the nine months ended June 30, 2019 compared to $498,017 for the nine months ended June 30, 2018.

For the three months ended June 30, 2019, our depreciation, depletion, and accretion expense decreased by $1,572 compared to the three months ended June 30, 2018, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition. No significant asset purchases were made in the quarter ended June 30, 2019.

For the nine months ended June 30, 2019, our depreciation and accretion expense decreased by $4,794 compared to the nine months ended June 30, 2018, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition. No significant depreciable asset purchases were made in the quarter ended June 30, 2019.

For the three months ended June 30, 2019, rental and other income increased by $1,249 compared to the three months ended June 30, 2018.

For the nine months ended June 30, 2019, rental and other income decreased by $5,549 compared to the nine months ended June 30, 2018.

For the three months ended June 30, 2019, there were no significant increases or decreases for interest income compared to the three months ended June 30, 2018.

For the nine months ended June 30, 2019, there were no significant increases or decreases for interest income compared to the nine months ended June 30, 2018.

As a result of the above transactions, we recorded a decrease of $29,064 in our net loss and loss from operations for the three months ended June 30, 2019 compared to the three months ended June 30, 2018.

As a result of the above transactions, we recorded a decrease of $107,764 in our net loss and loss from operations for the nine months ended June 30, 2019 compared to the nine months ended June 30, 2018. As discussed above, this decrease was primarily due to decreases in engineering and audit fees.

Operations

~~The~~Since the ~~first~~inception ~~SAGD~~of ~~well~~our ~~pair,~~current ~~for~~business ~~the SAGD Project~~plan, ~~was~~our ~~drilled~~operations tohave aconsisted ~~vertical depth~~ of ~~approximately~~various ~~650~~exploration ~~meters~~and ~~with~~start-up aactivities ~~horizontal length of 780 meters each. Steam injection~~relating ~~commenced~~to inour ~~May~~properties, ~~2014~~including ~~and~~the ~~production~~acquisition ~~started in September~~ of ~~2014.~~lease ~~Production~~holdings, ~~from~~raising ~~this~~capital, ~~one~~locating ~~SAGD~~joint ~~well~~venture ~~pair~~partners, ~~increased~~acquiring ~~significantly~~and ~~over~~analyzing ~~the~~seismic ~~18-month~~data, ~~period~~complying itwith ~~produced.~~environmental ~~Over January and February of 2016 production from the SAGD Project averaged 615 bopd~~regulations, ~~on a 100% basis (154 bopd net to us)~~drilling, ~~with~~testing anand ~~average~~analyzing ~~SOR~~ of ~~2.1~~wells ~~from one SAGD well pair. The SOR is reflective of the amount of steam needed~~ to ~~produce~~define ~~one~~our ~~barrel of~~ oil. ~~This SAGD Project was temporarily suspended at the end of February 2016. The capital costs~~sands ~~of the existing SAGD Project steam plant facility~~reservoir, ~~with pipelines~~ and ~~one~~development ~~SAGD~~planning ~~well~~of ~~was~~our ~~approximately~~Alberta ~~$26.5~~Energy ~~million~~Regulatory (~~Cdn $34.8 million~~“AER”) onapproved athermal ~~100%~~recovery ~~working interest basis~~projects, of which includes our ~~share~~joint isSteam ~~covered~~Assisted ~~under~~Gravity ~~the~~Drainage ~~Farmout~~Demonstration ~~Agreement.~~Project ~~These capital costs do not include~~ (the ~~start-up~~“SAGD ~~operating~~Project”) ~~expenses~~where towe ~~initiate~~have ~~oil~~a ~~production~~25% working ~~from the SAGD well pair~~interest.

~~The~~Our main ~~current~~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.

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.11

~~Our Sawn Lake properties are in a pre-commercial~~The stage of development and engineering work has, and is, continuing towards the commercial expansion of our joint SAGD Project, for the expansion of the existing battery. In early May of 2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site and received regulatory approval in December 2017. This expansion application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs will need to be operating to achieve this production ~~level.~~results ~~We and our joint venture partners continue to work towards the anticipated reactivation and expansion~~ of the ~~existing~~ SAGD Project ~~facility~~successfully ~~site.~~confirmed ~~The SAGD Project development plan will be done in stages to reduce initial financial costs. The first stage anticipates~~ the ~~reactivation~~capability of the ~~existing~~Bluesky ~~SAGD~~reservoir battery and existing SAGD well pair, along with the drilling of one additional SAGD well pair, initially producing from 2 well pairs. The second stage anticipates drilling an additional three SAGD well pairs to produce upusing ~~to 3,200 bopd and the expansion of the existing SAGD facility~~thermal torecovery ~~generate the additional steam required~~technology. WeThe ~~anticipate~~following ~~our~~graph ~~near-~~sets ~~and~~out ~~long-term funding of our operations to be financed through~~ the ~~existing~~production ~~Farmout~~levels ~~Agreement,~~that ~~future earn-in agreements, and cash flow from~~ the ~~reactivation of the existing~~ SAGD Project achieved. ~~We anticipate~~These ~~drilling~~production ~~future~~numbers compare ~~wells~~favorably ~~on our properties~~ to ~~further~~analogous ~~expand~~reservoirs ~~the boundary of the Sawn Lake Bluesky reservoir. We also intend to negotiate with the Petroleum and Natural Gas holders~~ in ~~the~~thermal ~~area~~recovery ofprojects ~~our~~that ~~leases,~~we toare ~~enter~~monitoring ~~into further downhole contribution agreements to acquire logs~~ and ~~cores~~using ofas ~~the~~a ~~Bluesky~~basis ~~formation, in order to expand the boundaries~~ of ~~the oil sands reservoir and save on drilling costs and reduce our environmental footprint~~comparison.

13In early May of 2016, an amended application was submitted to the AER for a commercial expansion of the existing SAGD Project facility site and received regulatory approval in December 2017. This expansion application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs will need to be operating to achieve this production level. The SAGD Project development plan will be done in stages to reduce initial financial costs. The first stage anticipates the reactivation of the existing SAGD facility and existing SAGD well pair, along with the drilling of one additional SAGD well pair, initially producing from two SAGD well pairs. The second stage anticipates drilling an additional three SAGD well pairs to produce up to 3,200 bopd and the expansion of the existing SAGD facility to generate the additional steam required. The lead time to acquiring the necessary equipment and commencing operations is estimated to be about 18 months and another 6 months is required for the start of bitumen production (after development of the steam chamber). We anticipate our near- and long-term funding of our operations to be financed through the existing Farmout Agreement, future earn-in agreements, and cash flow from the reactivation of the existing SAGD Project. We also intend to negotiate with the Petroleum and Natural Gas holders in the area of our leases, to enter into further downhole contribution agreements to acquire additional logs and cores of the Bluesky formation, in order to expand the boundaries of the oil sands reservoir we have already defined and save on drilling costs and reduce our environmental footprint. We and our joint venture partners continue to move forward with SAGD Project with completing detailed engineering and assessing potential marketing arrangements for the commercial development expansion to 3,200 bopd (100% basis). As of June 30, 2019, a Sawn Lake full field development plan using SAGD batteries has been defined by the operator of the SAGD Project.

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 previously ~~August 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 at least 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 ~~our~~ HCSS Project.

Our Company to date has, but not limited to, drilled or participated in 13 wells over our Sawn Lake leases to expand the boundaries of the Bluesky oil sands reservoir; commissioned various independent reservoir simulation studies of our properties; successfully produced bitumen from the SAGD Project, which outperformed independent reservoir production type curves; acquired AER approvals for two thermal recovery projects, which includes our joint SAGD Project facility expansion to produce up to 3200 bopd; successfully entered into Farmout Agreements; and successfully applied to continue 5 leases, where resources were assigned, past their initial expiry dates.12

Our Company to date has, but not limited to, drilled or participated in 13 wells over our Sawn Lake leases to expand the boundaries of the Bluesky oil sands ~~acreage~~reservoir; ascommissioned various independent reservoir simulation studies of ~~June~~our ~~30,~~properties; ~~2019,~~successfully ~~covers~~produced ~~37,322~~bitumen ~~gross~~from ~~acres~~the ~~(29~~SAGD Project,~~383~~ ~~net~~which ~~acres)~~outperformed ofindependent ~~land~~reservoir ~~under~~production ~~nine~~type ~~oil~~curves; ~~sands~~acquired ~~leases.~~AER ~~Until~~approval for two thermal recovery projects, which includes our ~~Company~~joint ~~extends~~SAGD ~~its~~Project facility expansion to produce up to 3200 bopd; successfully entered into Farmout Agreements; and we have successfully applied to the AER to continue the best sections of our oil sands ~~leases~~properties ~~“into~~past ~~perpetuity”~~their initial lease expiry dates, ~~based~~where onresources were identified. Under the ~~Alberta~~oil ~~governmental~~sands lease continuation regulations an operator or leaseholder must demonstrate certain levels of exploration and development by providing the AER with drilling, coring and seismic data within a certain timeframe in order to maintain the lease past its expiry date. Our Company’s Sawn Lake oil sands properties under lease as of September 30, 2019, covers 19,610 gross acres (13,442 net acres) of land under seven oil sands leases. The lease expiration dates of our ~~nine~~Company’s oil sands leases are as follows:

1. 14Out of 20,~~549~~242 gross acres (813,~~571~~284 net acres) under five oil sands leases were set to expiry on July 10, 2018, ~~and~~14,549 ~~were~~gross ~~subsequently~~acres (8,571 net acres) were granted continuation under the Alberta Oil Sands Tenure regulations and ~~now~~ have no set expiry date. In November of 2017, our Company’s joint venture partner and operator of two of ~~the~~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. ~~The vast majority of the resources that the Company has identified to date are within these five leases which have been continued to perpetuity and the lease referred to in #3 below.~~ These continued leases ~~have~~are nonow ~~future~~held ~~expiry~~by ~~dates~~our ~~but~~Company ~~are~~for perpetuity, subject to yearly escalating rental payments until they are deemed to be producing leases;.

2. 19,610 gross acres (17,649 net acres) under the three most northern oil sands leases ~~are~~were set to expire on August 19, 2019. WeIn ~~applied~~August ~~for~~2019, aour ~~term~~Company ~~extension~~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 ~~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 ~~and~~19, 2019, 17,712 gross acres (15,941 net acres) expired without being continued. These expired lands were primarily areas where we determined that there was no or limited exploitable resources.

3. 3,163 gross acres (3,163 net acres) under one oil sands lease are set to expire on April 9, 2024. WeIt ~~believe~~is our Company’s opinion that we have already met the governmental requirements for this lease, and we ~~currently~~will ~~intend~~be toapplying ~~apply~~ to continue this lease into perpetuity.

The development progress of our Sawn Lake oil sands properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can, and often, do delay development of similar projects and our projects. Because of these and other factors, our oil sands ~~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:

	Three Months Ended			Three Months Ended
	December 31, 2019			December 31, 2018
Revenue	$	–		$	–
Provincial royalty expenses		–			–
Revenue, net of royalty		–			–
Expenses
Operating expenses		27,738			39,660
Operating expense covered by Farmout		(27,738	)		(39,660	)
General and administrative		30,321			53,855
Depreciation, accretion and depletion		10,843			11,442
Net loss from operations		(41,164	)		(65,297	)
Other income and expenses
Rental and other income		(2,047	)		2,046
Interest income		1,994			1,810
Net loss	$	(41,217	)	$	(61,441	)

There was no production volumes or revenues for the years ending December 31, 2019 and 2018, due to a majority of our Company’s Joint Venture partners voting to temporarily suspend operations of the SAGD Project at the end of February 2016. In accordance with the Farmout Agreement we entered into on July 31, 2013, the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project in return for a net 25% working interest in two oil sands leases where we had a working interest of 50% before the execution of the Farmout Agreement. Under the terms of the Farmout Agreement the Farmee is required to provide funding to cover the monthly administrative expenses of our Company provided that such funding shall not exceed $30,000 per month. The Farmee shall continue to cover our Company’s administrative costs up to $30,000 per month until completion in all substantial respects of the SAGD Project agreement entered into between the Company and the operator of the SAGD Project. Our net operating margin after operating expenses is zero, under the Farmout Agreement, any negative operating cash flows are reimbursed to us to fund our share of the SAGD Project. Therefore, the total share of the capital costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, as of December 31, 2019, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $21.1 million (Cdn$27.4 million) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project. These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator, production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; the operating expenses associated with the steaming and production of the one SAGD well pair when the facility was producing; and the expenses associated the monthly shut-in operations of the SAGD Project facility.

For the three months ended December 31, 2019, our general and administrative expenses decreased by $23,534 compared to the three months ended December 31, 2018, which was primarily due to decreases in office rent and auditor fees. We received $90,000 during this quarter from the Farmee in accordance with a Farmout Agreement to offset some of our monthly expenses. After adjusting out the non-cash item for foreign exchange and the funds we received from the Farmee, our general and administrative expenses were $119,643 for the three months ended December 31, 2019 compared to $146,732 for the three months ended December 31, 2018.

For the three months ended December 31, 2019, our depreciation, depletion, and accretion expense decreased by $599 compared to the three months ended December 31, 2018, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition. No significant asset purchases were made in the quarter ended December 31, 2019.

For the three months ended December 31, 2019, there was $4,093 decrease for rental and other income compared to the three months ended December 31, 2018.

As a result of the above transactions, we recorded a decrease of $20,224 in our net loss for the three months ended December 31, 2019 compared to the three months ended December 31, 2018. As discussed above, this decrease was primarily due to decreases in office rent fees and audit fees.

Liquidity and Capital Resources

As of ~~June~~December 3031, 2019, our total assets were $22,~~676~~672,~~573~~085 compared to $22,~~827~~677,~~332~~977 as of September 30, ~~2018~~2019.

Our total liabilities as of ~~June~~December 3031, 2019 were $~~527~~606,~~382~~709 compared to $~~538~~571,~~604~~384 as of September 30, ~~2018~~2019. There was no significant change in our total liabilities from the September 30, ~~2018~~2019 year end.

Our working capital (current liabilities subtracted from current assets) is as follows:

	Nine months Ended		Year Ended
	Three months Ended		Year Ended
	June 30, 2019		September 30, 2018
	December 31, 2019		September 30, 2019
Current Assets	$	~~163~~147,~~394~~497	$	~~363~~167,~~891~~379
Current Liabilities		2591,~~589~~739		4570,~~137~~992
Working Capital	$	~~137~~55,~~805~~758	$	~~318~~96,~~754~~387

As of ~~June~~December 3031, 2019, we had working capital of $~~137~~55,~~805~~758 compared to a working capital of $~~318~~96,~~754~~387 as of September 30, ~~2018~~2019. This decrease of $~~180~~40,~~949~~ 629 is primarily due to cash used for general and administrative expenses.

As reported on our condensed Consolidated Statement of Cash Flows under “Operating Activities”, for the ~~nine~~three months ended ~~June~~December 3031, 2019, our net cash used in operating activities was $~~203~~1,~~228~~754 compared to $~~309~~81,~~396~~855 for the ~~nine~~three months ended ~~June 30~~December 31, 2018. This decrease of $~~106~~80,~~168~~101 in our operating activities was due to a decrease inof $20,224 for general and administrative expenses and a decrease of $60,476 from changes in non-cash working capital.

As reported on our condensed Consolidated Statement of Cash Flows under “Investing Activities”, ~~cash~~we ~~flows~~had ~~used~~a decrease of $38,632 on investment in our oil and gas properties for the ~~nine~~three months ended ~~June~~December 3031, 2019 ~~decreased by $516~~,~~044~~ compared to the ~~nine~~three months ~~ended June 30, 2018. This decrease was a~~ ~~result of less expenditures used in our oil and gas properties in comparison to the nine months~~ ended ~~June~~December 3031, 2018. InThere ~~the~~were ~~nine months~~no ~~ended~~significant ~~June~~investing ~~30,~~activities ~~2018,~~during wethese paid a cash contribution of $395,500 ($500,000 Cdn) 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 leasesperiods.

As reported on our condensed Consolidated Statement of Cash Flows under “Financing Activities”, for the ~~nine~~three months ended ~~June~~December 3031, 2019 weand ~~received~~December ~~$15~~31,~~000~~ ~~from one~~2018, ofwe ~~our~~had ~~directors~~a ~~for~~decrease ~~the exercise~~ of ~~his~~$15,000 ~~stock~~compared ~~options.~~to ~~For~~ the ~~nine~~three months ended ~~June~~December 3031, 2018 ~~we received a distribution~~. ~~refund~~There ofwere ~~$243,574~~no ~~which~~financing ~~was~~activities ~~related~~for tothe athree ~~return~~months ofended ~~capital~~December ~~distribution~~31, ~~our~~2019 ~~Company issued in September of 2013~~period.

Our cash and cash equivalents as of June 30, 2019 was $34,364 compared to $438,854 as of June 30, 2018. This decrease of $404,490 in cash was primarily due to the decrease in general and administrative expenses and the $243,574 distribution refund described above.14

AsOur cash and cash equivalents as of ~~June~~December 3031, 2019 was $37, we706 ~~had~~compared noto ~~long-term~~$181,691 ~~debt~~as ~~other~~of ~~than~~December ~~our~~31, ~~estimated~~2018. ~~future~~This ~~asset~~decrease ~~retirement~~of ~~obligations~~$143,985 in oncash ~~oil~~was primarily due to the cash used in general and ~~gas~~administrative ~~properties~~expenses.

~~Our current SAGD Project capital and operating~~As ~~costs are covered under the terms~~ of ~~the~~December ~~Farmout Agreement. As described above the Farmee shall continue to cover our administrative costs up to $30~~31,~~000~~ ~~per month~~2019, ~~under~~we ~~the~~had ~~Farmout~~no ~~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,~~debt ~~we anticipate that, among~~ other ~~alternatives,~~than ~~we may raise funds during the next twenty-four months through sales of~~ our ~~equity~~estimated ~~securities,~~future ~~debt,~~asset ~~or entering~~retirement ~~into~~obligations ~~another~~on ~~form~~oil 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 ifgas ~~so, we may be forced to delay our business plans until adequate funding is obtained~~properties.

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

Off-Balance Sheet Arrangements

WeThere is dono ~~not~~transaction, ~~have~~arrangement, or other relationship between our Company or any ~~off-balance~~of ~~sheet~~our ~~arrangements~~subsidiaries and an unconsolidated or affiliated entity that is not reflected on our Company’s Financial Statements that is required to be disclosed by our Company in our SEC filings and is not already disclosed.

Cautionary Note Regarding Forward-Looking Statements

This quarterly report on Form 10-Q, including all referenced Exhibits, contains “forward-looking statements” within the meaning of the United States federal securities laws. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, projected costs and plans and objectives of management for future operations, are forward-looking statements. The words “may,” “believe,” “intend,” “will,” “anticipate,” “expect,” “estimate,” “project,” “future,” “plan,” “strategy,” “probable,” “possible,” or “continue,” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters, often identify forward-looking statements. For these statements, Deep Well claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. The forward-looking statements in this quarterly report include, among others, statements with respect to:

●

our current business strategy;

●

our future financial position and projected costs;

●

our projected sources and uses of cash;

●

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

●

our drilling and testing plans;

●

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

●

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

●

our reserves and resources estimates;

●

the timing and sources of our future funding;

●

the quantity and value of our reserves;

●

the intent to issue a distribution to our shareholders;

●

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

●

our plans for development of our Sawn Lake properties;

●

production levels from our current SAGD Project;

●

costs of our current SAGD Project;

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

●

additional sources of funding from the Farmout Agreement;

●

funding from the Farmee to cover our monthly operating expenses;

●

our access and availability to third-party infrastructure;

●

present and future production of our properties;

● our ability to extend our ~~leases~~remaining lease; past ~~their~~its primary expiration ~~dates~~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;15

●

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~~shareholders’ equity;

●

competition;

●

changes in labor, equipment and capital costs;

●

future acquisitions or strategic partnerships;

●

the risks and costs inherent in litigation;

●

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

●

product supply and demand;

●

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

●

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

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

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

●

our ability to meet the minimum level of production requirements on our oil sands leases as set out by the AER in order to eliminate future escalating oil sands lease rents on our continued leases;

●

changes in general business or economic conditions;

●

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

●

geological, technical, drilling and processing problems;

●

third party performance of obligations under contractual arrangements;

●

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

●

treatment under governmental regulatory regimes and tax laws;

●

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

●

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

●

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

●

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

●

fluctuations in currency and interest rates; and

●

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

The preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description of risks and uncertainties, see the sections entitled “Risk Factors” and “Environmental Laws and Regulations” of our annual report on Form 10-K for the fiscal year ended September 30, ~~2018~~2019 filed with the ~~United States Securities and Exchange Commission (“~~SEC~~”) on~~ ~~December 21, 2018~~ and the ~~Alberta Securities Commission (“~~ASC”) on SEDAR on ~~April 12~~January 13, ~~2019~~2020.. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated or expected. Any forward-looking statement speaks only as of the date on which it was made and, except as required by law, we disclaim any obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. However, any further disclosures made on related subjects in subsequent reports on Forms 10-K, 10-Q, 8-K and any other SEC filing or amendments thereto should be consulted.

1716

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.

CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of our fiscal quarter ended ~~June~~ 30December 31, 2019, an evaluation of the effectiveness of our “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our principal executive officer and principal financial officer. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that as of the end of that quarter, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

Changes In Internal Control Over Financial Reporting

During the fiscal quarter ended ~~June~~December 3031, 2019, there were no changes in our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

1817

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

~~None~~On October 28, 2019, Provident Premier Master Fund Ltd. (the “Plaintiff”), filed and served an Amended Statement of Claim against Northern Alberta Oil Ltd., Deep Well Oil & Gas (Alberta) Ltd., Andora Energy Corporation and MP Energy West Canada Corp. (the “Defendants”) in the Court of Queen’s Bench of Alberta Judicial District of Calgary. The Original Statement of Claim was filed on November 1, 2018 but our Company was never served so we were not aware of it.

The Plaintiff claims that on December 12, 2003, Nearshore Petroleum Corporation (“Nearshore”) entered into a royalty agreement with Northern Alberta Oil Ltd. (“Northern”) in which Northern granted a 6.5% gross overriding royalty (“GORR”) in all petroleum substances produced, saved and marketed from six of our Company's oil sands leases located within our Company's Sawn Lake properties.

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

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

ITEM 1A.

RISK FACTORS

Although we are a smaller reporting company as defined by Rule 12b-2 under the Exchange Act and are therefore not required to provide the information required under this item, there have been no material changes in our risk factors from those disclosed in our annual report on Form 10-K for the fiscal year ended September 30, ~~2018~~2019, filed with the Alberta Securities Commission on SEDAR on ~~April 12~~January 13, ~~2019~~2020 and the U.S. Securities and Exchange Commission on ~~December~~January 2113, ~~2018~~2020.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.

OTHER INFORMATION

Information to be Reported on Form 8-K

Deep Well reported all information that was required to be disclosed on Form 8-K during the period covered by this quarterly report on Form 10-Q for the period ended ~~June 30~~December 31, 2019.

Shareholder Nominations

There have been no changes to the procedures by which shareholders may recommend nominees to our Board of Directors during the time period covered by this quarterly report on Form 10-Q for the period ended ~~June~~December 3031, 2019.

ITEM 6.

EXHIBITS

Exhibit No.		Description
31.1		Certification of President and Chief Executive Officer pursuant to Rule 13a-14(a).
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a).
32.1		Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101		Interactive Data Files

2019

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	DEEP WELL OIL & GAS, INC.
	By	/s/ Horst A. Schmid
		Dr. Horst A. Schmid
		Chief Executive Officer and President
		(Principal Executive Officer)
	Date	~~August~~February 1419, ~~2019~~2020
	By	/s/ Curtis J. Sparrow
		Mr. Curtis James Sparrow
		Chief Financial Officer
		(Principal Financial and Accounting Officer)
	Date	~~August~~February 1419, ~~2019~~2020

2120

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