10-Q

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, 2017

Or

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

For the transition period from ________to________

Commission file number 0-24012

DEEP WELL OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada	98-0501168
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Suite 700, 10150 - 100 Street, Edmonton, Alberta, Canada	T5J 0P6
(Address of principal executive offices)	(Zip Code)

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

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

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 ☐ No þ

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☐ No þ

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

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

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company þ

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

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

As of the date of filing this quarterly report on Form 10-Q with the U.S. Securities and Exchange Commission (the “SEC”), Deep Well Oil & Gas, Inc. had outstanding 229,374,605 shares of common stock.

TABLE OF CONTENTS  

		Page Number
PART I – FINANCIAL INFORMATION
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)	3
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	12
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	18
ITEM 4.	CONTROLS AND PROCEDURES	18
PART II – OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	18
ITEM 1A.	RISK FACTORS	18
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	18
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	18
ITEM 4.	MINE SAFETY DISCLOSURES	18
ITEM 5.	OTHER INFORMATION	19
ITEM 6.	EXHIBITS	19
SIGNATURES

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Condensed Consolidated Balance Sheets

June 30, 2017 and September 30, 2016

	June 30,			September 30,
	2017			2016
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,159,152		$	1,400,922
Accounts receivable		111,236			22,577
Prepaid expenses		37,122			32,951
Total Current Assets		1,307,510			1,456,450
Long term investments		390,560			384,247
Oil and gas properties, net, based on full cost method of accounting		21,265,643			21,164,415
Property and equipment, net		139,763			161,855
TOTAL ASSETS	$	23,103,476		$	23,166,967
LIABILITIES
Current Liabilities
Accounts payable and accrued liabilities	$	116,005		$	47,506
Accounts payable and accrued liabilities – related parties		6,403			2,469
Total Current Liabilities		122,408			49,975
Asset retirement obligations (Note 7)		470,230			452,533
TOTAL LIABILITIES		592,638			502,508
(Commitments and contingencies (Note 11)
SHAREHOLDERS’ EQUITY
Common Stock: (Note 8)
Authorized: 600,000,000 shares at $0.001 par value
Issued and outstanding: 229,374,605 shares
(September 30, 2016 – 229,374,605 shares)		229,374			229,374
Additional paid in capital		42,845,292			42,842,978
Accumulated deficit		(20,563,828	)		(20,407,893	)
Total Shareholders’ Equity		22,510,838			22,664,459
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	23,103,476		$	23,166,967

See accompanying notes to the condensed consolidated financial statements

1

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, 2017 and 2016

	Three Months Ended			Three Months Ended			Nine Months Ended			Nine Months Ended
	June 30, 2017			June 30, 2016			June 30, 2017			June 30, 2016
Revenue	$	–		$	–		$	–		$	150,669
Royalty expenses		–			–			–			(22,977	)
Revenue, net of royalty		–			–			–			127,692
Expenses
Operating expenses		43,392			85,045			99,879			697,814
Operating expenses covered by Farmout		(43,392	)		(85,045	)		(99,879	)		(570,122	)
General and administrative		40,865			105,465			115,472			398,929
Depreciation, accretion and depletion		15,443			17,397			45,479			51,924
Net loss from operations		(56,308	)		(122,862	)		(160,951	)		(450,853	)
Other income and expenses
Rental and other income		194			142			2,531			8,425
Interest income		812			896			2,485			2,626
Net loss and comprehensive loss	$	(55,302	)	$	(121,824	)	$	(155,935	)	$	(439,802	)
Net loss per common share
Basic and Diluted	$	(0.00	)	$	(0.00	)	$	(0.00	)	$	(0.00	)
Weighted Average Outstanding
Shares (in thousands)
Basic and Diluted		229,374			229,374			229,374			229,374

See accompanying notes to the condensed consolidated financial statements

2

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

(Unaudited)

Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended June 30, 2017 and 2016

	June 30,			June 30,
	2017			2016
CASH PROVIDED BY (USED IN):
Operating Activities
Net loss	$	(155,935	)	$	(439,802	)
Items not affecting cash:
Share-based compensation		2,314			185,903
Depreciation, accretion and depletion		45,479			51,924
Net changes in non-cash working capital (Note 10)		(20,397	)		1,362
Net Cash Used in Operating Activities		(128,539	)		(200,613	)
Investing Activities
Purchase of equipment		(2,552	)		–
Investment in oil and gas properties		(112,859	)		(93,909	)
Long term investments		2,180			2,145
Net Cash Used in Investing Activities		(113,231	)		(91,764	)
Financing Activities
Proceeds from issuance of common stock		–			–
Net Cash Provided by Financing Activities		–			–
Decrease in cash and cash equivalents		(241,770	)		(292,377	)
Cash and cash equivalents, beginning of period		1,400,922			1,786,270
Cash and cash equivalents, end of period	$	1,159,152		$	1,493,893
Supplemental Cash Flow Information:
Cash paid for interest	$	–		$	–
Cash paid for income taxes	$	–		$	–

See accompanying notes to the condensed consolidated financial statements

3

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

(Unaudited)

Notes to the Condensed Consolidated Financial Statements

June 30, 2017

1. NATURE OF BUSINESS AND BASIS OF PRESENTATION

Nature of Business

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

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

Basis of Presentation

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

These interim condensed consolidated financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated financial statements for the year ended September 30, 2016.

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, 2016.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

These 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 30, 2017, 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.

4

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 30, 2017 and September 30, 2016, asset retirement obligations amount to $470,230 and $452,533, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.

Financial, Concentration and Credit Risk

The Company’s consideration or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit insurance limit. As of June 30, 2017, the Company has approximately $525,474 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 30, 2017 the Company recorded no oil sales, however and for the year ended September 30, 2016, the Company has recorded oil sales received from the operator of the Company’s producing properties. The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s joint venture partner who sells all of the Company’s oil production to 11 purchasers in the oil and gas industry. The Company does not require collateral and management periodically evaluates the operator’s financial statements and the collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and that the risk of loss is minimal.

Basic and Diluted Net Income (Loss) Per Share

Basic net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were 11,530,000 potentially dilutive securities excluded from the the diluted earnings per share calculation because their effect would be antidilutive.

Recently Adopted Accounting Standards

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

The Company does not expect the adoption of any other recent accounting pronouncements to have a material impact on the Company’s financial statements.

5

3. OIL AND GAS PROPERTIES

The Company’s oil sands acreage as of June 30, 2017, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:

1) 32 sections of land under 5 oil sands leases are set to expire on July 10, 2018. Of the 5 oil sands leases totaling 32 sections of land, it is the Company’s opinion that the Company has already met the governmental requirements on 17 of the 32 sections to continue these sections into perpetuity. These 17 sections contain the majority of the resources identified to date on these 5 oil sands leases. The Company has completed or is in the process of applying for continuation of these leases or parts of the leases where the majority of the oil sands resources have been confirmed. Currently, 11 out of the 17 sections that contain the majority of the resources identified to date have been granted continuance under the Alberta governmental tenure guidelines;

2) 31 sections of land under 3 oil sands leases are set to expire on August 19, 2019; and

3) 5 sections of land under 1 oil sands lease are set expire on April 9, 2024. It is the Company’s opinion that the Company has already met the governmental requirements for this lease and it will be applying to continue all 5 sections of 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 30, 2017, 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 $)		(Cdn $)
2017	$	9,303	$	12,073
2018	$	32,069	$	41,615
2019	$	20,823	$	27,022
2020	$	20,823	$	27,022
2021	$	19,788	$	25,678
Subsequent	$	177,539	$	230,388

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

This consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. Proven oil properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for the period ended June 30, 2017.

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

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

4. CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES

The following table illustrates capitalized costs relating to oil producing activities for the nine months ended June 30, 2017 and the fiscal year ended September 30, 2016:

	June 30, 2017			September 30, 2016
Unproved Oil and Gas Properties	$	21,347,636		$	21,238,052
Proved Oil and Gas Properties		–			–
Accumulated Depreciation and Depletion		(81,993	)		(73,637	)
Net Capitalized Cost	$	21,265,643		$	21,164,415

Depreciation and depletion expense for the nine months ended June 30, 2017 and 2016 were $8,356 and $8,489 respectively.

6

5. EXPLORATION ACTIVITIES

The following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the nine months ended June 30, 2017 and the fiscal year ended September 30, 2016:

	June 30, 2017		September 30, 2016
Acquisition of Properties:
Proved	$		$
Unproved	$	109,584	$	194,037
Exploration costs	$	10,960	$	39,658
Development costs	$		$

6. SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES

Accounts payable – related parties was $6,403 as of June 30, 2017 (September 30, 2016 - $2,469) for expenses to be reimbursed to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.

As of June 30, 2017, officers, directors, their families, and their controlled entities have acquired 53.63% of the Company’s outstanding common capital stock. This percentage does not include unexercised warrants or stock options.

The Company incurred expenses $104,031 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, 2017 (June 30, 2016 - $101,358). These amounts were fully paid as of June 30, 2017.

7. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At June 30, 2017, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $622,818 (September 30, 2016 - $616,191). The fair value of the liability at June 30, 2017 is estimated to be $470,230 (September 30, 2016 - $452,533) 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 26 years.

Changes to the asset retirement obligation were as follows:

	June 30, 2017		September 30, 2016
Balance, beginning of period	$	452,533	$	426,607
Liabilities incurred		–		–
Effect of foreign exchange		5,218		9,771
Disposal		–		–
Accretion expense		12,479		16,155
Balance, end of period	$	470,230	$	452,533

8. COMMON STOCK

Common Stock Issued and Outstanding

As of June 30, 2017, the Company had outstanding 229,374,605 shares of common stock.

Warrants

On November 23, 2016, warrants to acquire up to 52,155,221 common shares of the Company, expired unexercised. As of June 30, 2017, the Company had no outstanding warrants.

7

The following is a summary of warrant activity for the period ended June 30, 2017:

	Number of Warrants			Weighted Average Exercise Price		Intrinsic Value
Balance, September 30, 2016		52,155,221		$	0.105	$	–
Expired at November 23, 2016		(52,155,221	)		0.105		–
Balance, June 30, 2017		–		$	–	$	–
Outstanding Warrants, June 30, 2017		–		$	–	$	–

There were no warrants outstanding as of June 30, 2017 (September 30, 2016 – there were 52,155,221 warrants outstanding, which had a historical fair market value of $3,153,216).

9. STOCK OPTIONS

For the period ended June 30, 2017, the Company recorded share-based compensation expense related to stock options in the amount of $2,314 (September 30, 2016 – $237,971) on the stock options that were previously granted. As of June 30, 2017, there was no remaining unrecognized compensation cost of 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
$0.05 at June 30, 2017		3,450,000		0.97		0.05		3,450,000		0.05
$0.30 at June 30, 2017		250,000		1.33		0.30		250,000		0.30
$0.34 at June 30, 2017		450,000		1.43		0.34		450,000		0.34
$0.38 at June 30, 2017		6,780,000		2.22		0.38		6,780,000		0.38
$0.23 at June 30, 2017		600,000		2.38		0.23		600,000		0.23
		11,530,000		1.81	$	0.27		11,530,000	$	0.27

The aggregate intrinsic value of exercisable options as of June 30, 2017, was $Nil (September 30, 2016 - $Nil).

The following is a summary of stock option activity as at June 30, 2017:

	Number of Underlying Shares		Weighted Average Exercise Price		Weighted Average Fair Market Value
Balance, September 30, 2016		11,530,000	$	0.27	$	0.22
Balance, June 30, 2017		11,530,000	$	0.27	$	0.22
Exercisable, June 30, 2017		11,530,000	$	0.27	$	0.22

There were no remaining unvested stock options outstanding as of June 30, 2017 (September 30, 2016 – 200,000).

10. CHANGES IN NON-CASH WORKING CAPITAL

	Nine months ended			Nine months Ended
	June 30, 2017			June 30, 2016
Accounts receivable	$	(88,659	)	$	239,632
Prepaid expenses		(4,171	)		8,793
Accounts payable		72,433			(247,063	)
	$	(20,397	)	$	1,362

8

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 $11,559 per month (Cdn $15,000 per month). As of June 30, 2017, 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 on 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 $
2017 Q4 (July - September)	$	–	$	–
2018 Q1 (October - December)	$	6,141	$	7,969
2018 Q2 (January - March)	$	6,141	$	7,969
2018 Q3 (April - June)	$	6,141	$	7,969
2018 Q4 (July - September)	$	6,141	$	7,969
2019 Q1 (October - December)	$	6,141	$	7,969
2019 Q2 (January - March)	$	6,141	$	7,969
2019 Q3 (April - June)	$	6,141	$	7,969

12. SUBSEQUENT EVENTS

In August of 2017, the Company participated in a well on the Company’s Sawn Lake properties. The well was drilled to a total depth of 681 meters. The results of this core well were used for an application for continuation of the mineral rights on one of the Company’s oil sands leases.

On November 21, 2017, the Company’s joint venture partner and operator of two jointly held oil sands leases, where the Company has working interests, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue two oil sands leases that were set to expire on July 10, 2018. On January 29, 2018, the Company’s joint venture partner received approval from Alberta Energy, under the Alberta Oil Sands Tenure Regulation, to continue 2,816 gross hectares (704 hectares net to the Company) of lands, with a non-producing status, effective July 10, 2018. These two continued leases have no future expiry dates but are subject to yearly escalating rental payments until they are deemed to be producing leases.

On December 15, 2017, the Alberta Energy Regulator (“AER”) approved the previously submitted expansion application of the Company’s joint SAGD Project. The amended application sought approval to expand the existing SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be operating to achieve this production level. While the joint venture has not yet approved to expand the SAGD Project, currently, the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake. First production from the SAGD Project began on September 16, 2014. As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of the Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016.

On February 15, 2018, the Company participated in a well on one of its oil sands leases to acquire cores and logs through the Bluesky formation. The Company is currently analyzing the cores and logs.

9

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, 2016, filed with the U.S. Securities and Exchange Commission (“SEC”) on March 8, 2018.

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 Form 10-Q to “$” are to United States dollars and references to “Cdn$” are to Canadian dollars. On April 12, 2018, the daily rate of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.7939 as reported by the Bank of Canada. The following table sets forth the rates of exchange for the Cdn$, 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 daily rates of exchange for such periods as reported by the Bank of Canada.

Period Ending June 30	2017		2016
Rate at end of period	$	0.7706	$	0.7687
Average rate for the three month period	$	0.7436	$	0.7760

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, Edmonton, Alberta, Canada T5J 0P6, our telephone number is (780) 409-8144, and our fax number is (780) 409-8146. Deep Well Oil & Gas, Inc. is a Nevada corporation and trades on the OTC Marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com or www.DWOG.com. The contents of our website are not part of the quarterly report on Form 10-Q.

Results of Operations

Since the inception of our current business plan, our operations have consisted of various exploration and start-up activities relating to our properties, including the acquisition of lease holdings, raising capital, locating joint venture partners, acquiring and analyzing seismic data, complying with environmental regulations, providing project management, drilling, testing and analyzing of wells to define our oil sands reservoir, and development planning of our Alberta Energy Regulatory (“AER”) approved thermal recovery projects, 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, 2017			June 30, 2016			June 30, 2017			June 30, 2016
Revenue	$	–		$	–		$	–		$	150,669
Provincial royalty expenses		–			–			–			(22,977	)
Revenue, net of royalty		–			–			–			127,692
Expenses
Operating expenses		43,392			85,045			99,879			697,814
Operating expense covered by Farmout		(43,392	)		(85,045	)		(99,879	)		(570,122	)
General and administrative (excluding share-based compensation)		40,865			46,841			113,158			213,026
Share-based compensation		–			58,624			2,314			185,903
Depreciation, accretion and depletion		15,443			17,397			45,479			51,924
Net loss from operations		(56,308	)		(122,862	)		(160,951	)		(450,853	)
Other income and expenses
Rental and other income		194			142			2,531			8,425
Interest income		812			896			2,485			2,626
Net loss and comprehensive loss	$	(55,302	)	$	(121,824	)	$	(155,935	)	$	(439,802	)

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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, therefore there was no production volumes or revenues for the three month and nine month periods ending June 30, 2017. For the comparable three month period ending June 30, 2016, oil revenue totaled $Nil and no volumes of oil were produced, due to the shut-in of the SAGD Project. For the comparable nine month period ending June 30, 2016, we recorded oil revenue in the amount of $150,669 before deduction of royalties. For the nine month period ending June 30, 2016, the volume of oil delivered for five months of production was 19,156 barrels net to our Company, before royalties, with an average oil sales price of $7.87 per barrel ($10.48 per barrel Cdn). The realized sales price of our oil is discounted for diluent, blending, trucking, pipeline access and additional treating costs compared to the West Texas Intermediate (“WTI”) benchmark price, but paid in Canadian dollars. Our net operating margin after operating expenses is zero since at this time any negative operating margins are reimbursed to us under the farmout agreement we entered into on July 31, 2013 (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund our share of the current SAGD Project. Transportation costs are included in these operating costs. Therefore, the total share of the capital costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, the Farmee has since reimbursed our Company and/or paid the operator in total approximately $21.5 million ($26.7 million Cdn) for the Farmee’s share and our share of the capital costs and operating expenses of the SAGD Project as of November 30, 2017. These costs included the drilling and completion of one SAGD well pair; the purchase and transportation of equipment of which included the once through steam generator (“OTSG”), production tanks, water treatment plant, and power generators; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells; construction of pipelines and expenditures to connect and tie-in the source and disposal water wells to the steam plant facility along with a fuel source tie-in pipeline; equipment for processing and treating the bitumen production at the SAGD facility site; replacement of the electrical submersible pump; front end costs for the expansion; and the operating expenses associated with the steaming and production of the one SAGD well pair.

For the three months ended June 30, 2017, our general and administrative expenses decreased by $64,600 compared to the three months ended June 30, 2016, which was primarily due to a decrease of $58,624 in non-cash share-based compensation charged to expense. We also 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 items for share-based compensation and foreign exchange loss, and the funds we received from the Farmee, our general and administrative expenses were $142,904 for the three months ended June 30, 2017 compared to $132,759 for the three months ended June 30, 2016.

For the nine months ended June 30, 2017, our general and administrative expenses decreased by $283,457 compared to the nine months ended June 30, 2016, which was primarily due to a decrease of $183,589 in non-cash share-based compensation charged to expense and a decrease in engineering fees of $44,693. We also received $270,000 during the last nine months from the Farmee in accordance with the Farmout Agreement, to offset some of our monthly expenses. After adjusting out the non-cash items for share-based compensation and foreign exchange loss, and the funds we received from the Farmee, our general and administrative expenses were $420,264 for the nine months ended June 30, 2017 compared to $487,918 for the nine months ended June 30, 2016.

For the three months ended June 30, 2017, our depreciation, depletion, and accretion expense decreased by $1,954 compared to the three months ended June 30, 2016, 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, 2017.

For the nine months ended June 30, 2017, our depreciation and accretion expense decreased by $6,445 compared to the nine months ended June 30, 2016, 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 nine months ended June 30, 2017.

For the three months ended June 30, 2017, there were no significant increases or decreases in rental and other income compared to the three months ended June 30, 2016.

For the nine months ended June 30, 2017, rental and other income decreased by $5,894 compared to the nine months ended June 30, 2016.

For the three months ended June 30, 2017, there were no significant increases or decreases in interest income for three months ended June 30, 2016.

For the nine months ended June 30, 2017, there were no significant increases or decreases in interest income compared to the nine months ended June 30, 2016.

As a result of the above transactions, we recorded a decrease of $66,522 in our net loss for the three months ended June 30, 2017 compared to the three months ended June 30, 2016. As discussed above, this decrease was primarily due to a decrease in non-cash share-based compensation expenses.

As a result of the above transactions, we recorded a decrease of $283,867 in our net loss for the nine months ended June 30, 2017 compared to the nine months ended June 30, 2016. As discussed above, this decrease was primarily due to decreases in non-cash share-based compensation expenses.

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Operations

In accordance with the Farmout Agreement the Farmee has agreed to provide up to $40,000,000 in funding for our portion of the costs for the SAGD Project in return for a net 25% working interest in 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.

The first SAGD well pair established that SAGD thermal technology is effective in producing oil from the Bluesky reservoir formation at Sawn Lake. Our SAGD Project also provided valuable productivity information about the Bluesky reservoir. The following graph sets out the production levels since the project started producing. In October of 2015, the operator began steam rate trials to optimize production while lowering the steam injection rate, thereby lowering the steam to oil ratio (“SOR”). The SOR is reflective of the amount of steam needed to produce one barrel of oil. The average SOR for January and February of 2016 was 2.1.

 

These production numbers along with the corresponding SORs compare favorably to analogous reservoirs in thermal recovery projects that we are monitoring and using as a basis of comparison. The capital costs of the existing SAGD Project steam plant facility, with pipelines and one SAGD well was approximately $26.5 million (Cdn $34.8 million) on a 100% working interest basis, of which our share is covered under the Farmout Agreement (these capital costs do not include the start-up operating expenses to initiate oil production from the SAGD well pair). As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of our Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016.

The current SAGD Project has:

● 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 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 and increased significantly over the 18-month period it produced. In January and February of 2016 production from the SAGD Project reached a steady state averaging 615 bopd, on a 100% basis (154 bopd net to us), with an average SOR of 2.1 from one SAGD well pair. It is expected that a reactivation of the existing SAGD Project facility and current SAGD well pair will be part of the potential commercial expansion along with the previously AER approved second SAGD well pair. In early May of 2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would potentially increase the operation for up to a total of eight SAGD well pairs. The amended application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be operating to achieve this production level. The expanded facility will be designed to handle up to 3,200 bopd. The AER approval for the expansion of the existing SAGD Project was granted on December 15, 2017. While the joint venture has not yet approved to expand the SAGD Project, currently, the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake. Expanding the SAGD Project would be a significant step towards establishing commercially viability at Sawn Lake on a larger scale.

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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 to drill a well on one of our Sawn Lake oil sands leases in which we acquired cores and logs through the Bluesky formation. We are currently analyzing the cores and logs.

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

We currently we have a 90% working interest in six oil sands leases and a 100% working interest 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 in another two oil sands leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous and cover 42,383 gross acres (17,152 gross hectares) with our Company having 33,938 net acres (13,734 net hectares). The development progress of our properties is governed by several factors such as federal and provincial governmental regulations. Long lead times in getting regulatory approval for thermal recovery projects are commonplace in our industry. Road bans, winter access only roads and environmental regulations can, and often, do delay development of similar projects. Because of these and other factors, our oil sands project could take significantly longer to complete than regular conventional drilling programs for lighter oil.

Liquidity and Capital Resources

As of June 30, 2017, our total assets were $23,103,476 compared to $23,166,967 as of September 30, 2016. This decrease of $63,491 was primarily due to cash used for general and administrative expenses, offset by and an increase in our accounts receivable and oil and gas properties.

Our total liabilities as of June 30, 2017 were $592,638 compared to $502,508 as of September 30, 2016. This increase of $90,130 in our total liabilities was primarily due to the increase of outstanding accounts payable to the operator of the SAGD Project for operating expenses, which was subsequently reimbursed to us by the Farmee, in accordance with the terms of the Farmout Agreement.

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

	Nine Months Ended		Year Ended
	June 30, 2017		September 30, 2016
Current Assets	$	1,307,510	$	1,456,450
Current Liabilities		122,408		49,975
Working Capital	$	1,185,102	$	1,406,475

As of June 30, 2017, we had working capital of $1,185,102 compared to a working capital of $1,406,475 as of September 30, 2016. This decrease of $221,373 is mainly the result of cash used for general and administrative expenses. As of June 30, 2017, we had no long-term third party debt other than our estimated asset retirement obligations on oil and gas properties.

On July 31, 2013, we entered into the Farmout Agreement to fund our share of the costs of our joint SAGD Project. As of June 30, 2017, we recorded $25,187 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 condensed Consolidated Statement of Cash Flows under “Operating Activities”, for the nine months ended June 30, 2017, our net cash used in operating activities was $128,539 compared to $200,613 for the nine months ended June 30, 2016. This decrease of $72,074 was primarily the result of less cash used for general and administrative expenses.

As reported on our condensed Consolidated Statement of Cash Flows under “Investing Activities”, we had an increase of $18,950 in the investment in our oil and gas properties for the nine months ended June 30, 2017, compared to the nine months ended June 30, 2016. There were no significant investing activities during these periods.

As reported on our condensed Consolidated Statement of Cash Flows under “Financing Activities”, for the nine months ended June 30, 2017 and June 30, 2016, there was no cash inflow or outflow in financing activities.

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Our cash and cash equivalents as of June 30, 2017 was $1,159,152 compared to $1,493,893 as of June 30, 2016. This decrease of $334,741 in cash was primarily due to general and administrative expenses. As of June 30, 2017, we had no long-term debt other than our estimated asset retirement obligations on oil and gas properties.

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Cautionary Note Regarding Forward-Looking Statements

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

● our current business strategy;

● our future financial position and projected costs;

● our projected sources and uses of cash;

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

● our drilling and testing plans;

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

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

● our reserves and resources estimates;

● the timing and sources of our future funding.

● the quantity and value of our reserves;

● the intent to issue a distribution to our shareholders;

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

● our plans for development of our Sawn Lake properties;

● production levels from our current SAGD Project;

● costs of our current SAGD Project;

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

● additional sources of funding from the Farmout Agreement;

● funding from the Farmee to cover our monthly operating expenses;

● our access and availability to third-party infrastructure;

● present and future production of our properties; and

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

14

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;

● 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 to continue our oil sands leases beyond their expiry dates;

● 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, 2016 filed with the SEC on March 8, 2018. 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.

15

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 30, 2017, 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 and due to the fact that our Company was late in filing its quarterly report on Form 10-Q for the period ended June 30, 2017, our principal executive officer and principal financial officer have concluded that as of the end of that quarter, our disclosure controls and procedures were not 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 30, 2017, 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.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None.

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, 2016, filed with the SEC on March 8, 2018.

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.

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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, 2017.

Shareholder Nominations

Other than the recent adoption of our corporate governance and nominating committee charters as previously disclosed in our annual report on Form 10-K for the year ending September 30, 2016, there have been no changes to the procedures by which shareholders may recommend nominees to our Company’s Board of Directors during the time period covered by this quarterly report on Form 10-Q for the period ended June 30, 2017.

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

17

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	April 19, 2018
By	/s/ Curtis Sparrow
	Mr. Curtis James Sparrow
	Chief Financial Officer
	(Principal Financial and Accounting Officer)
Date	April 19, 2018

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EX-31.1

Exhibit 31.1

Certification of Chief Executive Officer

Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934

I, Dr. Horst A. Schmid, President and Chief Executive Officer of Deep Well Oil & Gas, Inc., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Deep Well Oil & Gas, Inc. for the quarterly period ended June 30, 2017;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	April 19, 2018
By:	/s/ Horst A. Schmid
	Dr. Horst A. Schmid
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification of Chief Financial Officer

Pursuant to Section 302 of the Sarbanes-Oxley Act and Rule 13a-14(a) or 15d-14(a)
under the Securities Exchange Act of 1934

I, Mr. Curtis James Sparrow, Chief Financial Officer of Deep Well Oil & Gas, Inc., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Deep Well Oil & Gas, Inc. for the quarterly period ended June 30, 2017;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	April 19, 2018
By:	/s/ Curtis Sparrow
	Mr. Curtis James Sparrow
	Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant To

18 U.S.C. Section 1350,

As Adopted Pursuant To

Section 906 Of The Sarbanes-Oxley Act Of 2002

In connection with the Quarterly Report of Deep Well Oil & Gas, Inc. (the “Company”) on Form 10-Q for the period ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dr. Horst A. Schmid, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Date:	April 19, 2018
By:	/s/ Horst A. Schmid
	Dr. Horst A. Schmid
	President and Chief Executive Officer

EX-32.2

Exhibit 32.2

Certification Pursuant To

18 U.S.C. Section 1350,

As Adopted Pursuant To

Section 906 Of The Sarbanes-Oxley Act Of 2002

In connection with the Quarterly Report of Deep Well Oil & Gas, Inc. (the “Company”) on Form 10-Q for the period ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Mr. Curtis James Sparrow, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Company.

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

Date:	April 19, 2018
By:	/s/ Curtis Sparrow
	Mr. Curtis James Sparrow
	Chief Financial Officer

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Document and Entity Information - shares	9 Months Ended
	Jun. 30, 2017	Apr. 11, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	DEEP WELL OIL & GAS INC
Entity Central Index Key	0000869495
Trading Symbol	DWOG
Amendment Flag	false
Current Fiscal Year End Date	--09-30
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Entity Filer Category	Smaller Reporting Company
Entity Common Stock Shares Outstanding		229,374,605

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Condensed Consolidated Balance Sheets - USD ($)	Jun. 30, 2017	Sep. 30, 2016
Current Assets
Cash and cash equivalents	$ 1,159,152	$ 1,400,922
Accounts receivable	111,236	22,577
Prepaid expenses	37,122	32,951
Total Current Assets	1,307,510	1,456,450
Long term investments	390,560	384,247
Oil and gas properties, net, based on full cost method of accounting	21,265,643	21,164,415
Property and equipment, net	139,763	161,855
TOTAL ASSETS	23,103,476	23,166,967
Current Liabilities
Accounts payable and accrued liabilities	116,005	47,506
Accounts payable and accrued liabilities - related parties	6,403	2,469
Total Current Liabilities	122,408	49,975
Asset retirement obligations (Note 7)	470,230	452,533
TOTAL LIABILITIES	592,638	502,508
(Commitments and contingencies (Note 11)
SHAREHOLDERS' EQUITY
Authorized: 600,000,000 shares at $0.001 par value Issued and outstanding: 229,374,605 shares (September 30, 2016 - 229,374,605 shares)	229,374	229,374
Additional paid in capital	42,845,292	42,842,978
Accumulated deficit	(20,563,828)	(20,407,893)
Total Shareholders' Equity	22,510,838	22,664,459
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$ 23,103,476	$ 23,166,967

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Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2017	Sep. 30, 2016
Balance Sheets [Abstract]
Common stock, shares authorized	600,000,000	600,000,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares issued	229,374,605	229,374,605
Common stock, shares outstanding	229,374,605	229,374,605

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Condensed Consolidated Statements of Operations and Comprehensive Loss (Unaudited) - USD ($) shares in Thousands	3 Months Ended		9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Statements of Operations and Comprehensive Income (Loss) [Abstract]
Revenue				$ 150,669
Royalty expenses				(22,977)
Revenue, net of royalty				127,692
Expenses
Operating expenses	43,392	85,045	99,879	697,814
Operating expenses covered by Farmout	(43,392)	(85,045)	(99,879)	(570,122)
General and administrative	40,865	105,465	115,472	398,929
Depreciation, accretion and depletion	15,443	17,397	45,479	51,924
Net loss from operations	(56,308)	(122,862)	(160,951)	(450,853)
Other income and expenses
Rental and other income	194	142	2,531	8,425
Interest income	812	896	2,485	2,626
Net loss and comprehensive loss	$ (55,302)	$ (121,824)	$ (155,935)	$ (439,802)
Net loss per common share
Basic and Diluted	$ (0.00)	$ (0.00)	$ (0.00)	$ (0.00)
Weighted Average Outstanding Shares (in thousands)
Basic and Diluted	229,374	229,374	229,374	229,374

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($)	9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating Activities
Net loss	$ (155,935)	$ (439,802)
Items not affecting cash:
Share-based compensation	2,314	185,903
Depreciation, accretion and depletion	45,479	51,924
Net changes in non-cash working capital (Note 10)	(20,397)	1,362
Net Cash Used in Operating Activities	(128,539)	(200,613)
Investing Activities
Purchase of equipment	(2,552)
Investment in oil and gas properties	(112,859)	(93,909)
Long term investments	2,180	2,145
Net Cash Used in Investing Activities	(113,231)	(91,764)
Financing Activities
Proceeds from issuance of common stock
Net Cash Provided by Financing Activities
Decrease in cash and cash equivalents	(241,770)	(292,377)
Cash and cash equivalents, beginning of period	1,400,922	1,786,270
Cash and cash equivalents, end of period	1,159,152	1,493,893
Supplemental Cash Flow Information:
Cash paid for interest
Cash paid for income taxes

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Nature of Business and Basis of Presentation

9 Months Ended

Jun. 30, 2017

Nature of Business and Basis of Presentation [Abstract]

NATURE OF BUSINESS AND BASIS OF PRESENTATION

1. NATURE OF BUSINESS AND BASIS OF PRESENTATION

Nature of Business

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

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

Basis of Presentation

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

These interim condensed consolidated financial statements follow the same significant accounting policies and methods of application as the Company’s annual consolidated financial statements for the year ended September 30, 2016.

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, 2016.

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Summary of Significant Accounting Policies

9 Months Ended

Jun. 30, 2017

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

These 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 30, 2017, 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 30, 2017 and September 30, 2016, asset retirement obligations amount to $470,230 and $452,533, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.

Financial, Concentration and Credit Risk

The Company’s consideration or related financial credit risk related to cash and cash equivalents depends on if funds are fully insured by either The Canada Deposit Insurance Corporation (“CDIC”), or The Credit Union Deposit Guarantee Corporation (“CUDGC”) deposit insurance limit. As of June 30, 2017, the Company has approximately $525,474 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 30, 2017 the Company recorded no oil sales, however and for the year ended September 30, 2016, the Company has recorded oil sales received from the operator of the Company’s producing properties. The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s joint venture partner who sells all of the Company’s oil production to 11 purchasers in the oil and gas industry. The Company does not require collateral and management periodically evaluates the operator’s financial statements and the collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and that the risk of loss is minimal.

Basic and Diluted Net Income (Loss) Per Share

Basic net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were 11,530,000 potentially dilutive securities excluded from the the diluted earnings per share calculation because their effect would be antidilutive.

Recently Adopted Accounting Standards

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

The Company does not expect the adoption of any other recent accounting pronouncements to have a material impact on the Company’s financial statements.

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Oil and Gas Properties

9 Months Ended

Jun. 30, 2017

Oil and Gas Properties [Abstract]

OIL AND GAS PROPERTIES

3. OIL AND GAS PROPERTIES

The Company’s oil sands acreage as of June 30, 2017, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:

1) 32 sections of land under 5 oil sands leases are set to expire on July 10, 2018. Of the 5 oil sands leases totaling 32 sections of land, it is the Company’s opinion that the Company has already met the governmental requirements on 17 of the 32 sections to continue these sections into perpetuity. These 17 sections contain the majority of the resources identified to date on these 5 oil sands leases. The Company has completed or is in the process of applying for continuation of these leases or parts of the leases where the majority of the oil sands resources have been confirmed. Currently, 11 out of the 17 sections that contain the majority of the resources identified to date have been granted continuance under the Alberta governmental tenure guidelines;

2) 31 sections of land under 3 oil sands leases are set to expire on August 19, 2019; and

3) 5 sections of land under 1 oil sands lease are set expire on April 9, 2024. It is the Company’s opinion that the Company has already met the governmental requirements for this lease and it will be applying to continue all 5 sections of 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 30, 2017, 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 $)		(Cdn $)
2017	$	9,303	$	12,073
2018	$	32,069	$	41,615
2019	$	20,823	$	27,022
2020	$	20,823	$	27,022
2021	$	19,788	$	25,678
Subsequent	$	177,539	$	230,388

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

This consists of comparing the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. Proven oil properties are reviewed for any write down on a field-by-field basis. No write downs were recognized for the period ended June 30, 2017.

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

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

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Capitalization of Costs Incurred in Oil and Gas Activities

9 Months Ended

Jun. 30, 2017

Capitalization of Costs Incurred in Oil and Gas Activities [Abstract]

CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES

4. CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES

The following table illustrates capitalized costs relating to oil producing activities for the nine months ended June 30, 2017 and the fiscal year ended September 30, 2016:

	June 30,  2017			September 30,  2016
Unproved Oil and Gas Properties	$	21,347,636		$	21,238,052
Proved Oil and Gas Properties		–			–
Accumulated Depreciation and Depletion		(81,993	)		(73,637	)
Net Capitalized Cost	$	21,265,643		$	21,164,415

Depreciation and depletion expense for the nine months ended June 30, 2017 and 2016 were $8,356 and $8,489 respectively.

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Exploration Activities

9 Months Ended

Jun. 30, 2017

Exploration Activities [Abstract]

EXPLORATION ACTIVITIES

5. EXPLORATION ACTIVITIES

The following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the nine months ended June 30, 2017 and the fiscal year ended September 30, 2016:

	June 30,  2017		September 30, 2016
Acquisition of Properties:
Proved	$		$
Unproved	$	109,584	$	194,037
Exploration costs	$	10,960	$	39,658
Development costs	$		$

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Significant Transactions with Related Parties

9 Months Ended

Jun. 30, 2017

Significant Transactions with Related Parties [Abstract]

SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES

6. SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES

Accounts payable – related parties was $6,403 as of June 30, 2017 (September 30, 2016 - $2,469) for expenses to be reimbursed to directors. This amount is unsecured, non-interest bearing, and has no fixed terms of repayment.

As of June 30, 2017, officers, directors, their families, and their controlled entities have acquired 53.63% of the Company’s outstanding common capital stock. This percentage does not include unexercised warrants or stock options.

The Company incurred expenses $104,031 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, 2017 (June 30, 2016 - $101,358). These amounts were fully paid as of June 30, 2017.

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Asset Retirement Obligations

9 Months Ended

Jun. 30, 2017

Asset Retirement Obligations [Abstract]

ASSET RETIREMENT OBLIGATIONS

7. ASSET RETIREMENT OBLIGATIONS

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At June 30, 2017, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $622,818 (September 30, 2016 - $616,191). The fair value of the liability at June 30, 2017 is estimated to be $470,230 (September 30, 2016 - $452,533) 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 26 years.

Changes to the asset retirement obligation were as follows:

	June 30, 2017		September 30, 2016
Balance, beginning of period	$	452,533	$	426,607
Liabilities incurred		–		–
Effect of foreign exchange		5,218		9,771
Disposal		–		–
Accretion expense		12,479		16,155
Balance, end of period	$	470,230	$	452,533

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Common Stock

9 Months Ended

Jun. 30, 2017

Common Stock [Abstract]

COMMON STOCK

8. COMMON STOCK

Common Stock Issued and Outstanding

As of June 30, 2017, the Company had outstanding 229,374,605 shares of common stock.

Warrants

On November 23, 2016, warrants to acquire up to 52,155,221 common shares of the Company, expired unexercised. As of June 30, 2017, the Company had no outstanding warrants.

The following is a summary of warrant activity for the period ended June 30, 2017:

	Number of Warrants			Weighted Average Exercise Price		Intrinsic Value
Balance, September 30, 2016		52,155,221		$	0.105	$	–
Expired at November 23, 2016		(52,155,221	)		0.105		–
Balance, June 30, 2017		–		$	–	$	–
Outstanding Warrants, June 30, 2017		–		$	–	$	–

There were no warrants outstanding as of June 30, 2017 (September 30, 2016 – there were 52,155,221 warrants outstanding, which had a historical fair market value of $3,153,216).

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Stock Options

9 Months Ended

Jun. 30, 2017

Stock Options [Abstract]

STOCK OPTIONS

9. STOCK OPTIONS

For the period ended June 30, 2017, the Company recorded share-based compensation expense related to stock options in the amount of $2,314 (September 30, 2016 – $237,971) on the stock options that were previously granted. As of June 30, 2017, there was no remaining unrecognized compensation cost of 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
$0.05 at June 30, 2017		3,450,000		0.97		0.05		3,450,000		0.05
$0.30 at June 30, 2017		250,000		1.33		0.30		250,000		0.30
$0.34 at June 30, 2017		450,000		1.43		0.34		450,000		0.34
$0.38 at June 30, 2017		6,780,000		2.22		0.38		6,780,000		0.38
$0.23 at June 30, 2017		600,000		2.38		0.23		600,000		0.23
		11,530,000		1.81	$	0.27		11,530,000	$	0.27

The aggregate intrinsic value of exercisable options as of June 30, 2017, was $Nil (September 30, 2016 - $Nil).

The following is a summary of stock option activity as at June 30, 2017:

	Number of Underlying Shares		Weighted Average Exercise Price		Weighted Average Fair Market Value
Balance, September 30, 2016		11,530,000	$	0.27	$	0.22
Balance, June 30, 2017		11,530,000	$	0.27	$	0.22
Exercisable, June 30, 2017		11,530,000	$	0.27	$	0.22

There were no remaining unvested stock options outstanding as of June 30, 2017 (September 30, 2016 – 200,000).

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Changes in Non-Cash Working Capital

9 Months Ended

Jun. 30, 2017

Changes in Non-Cash Working Capital [Abstract]

CHANGES IN NON-CASH WORKING CAPITAL

10. CHANGES IN NON-CASH WORKING CAPITAL

	Nine months ended			Nine months Ended
	June 30, 2017			June 30, 2016
Accounts receivable	$	(88,659	)	$	239,632
Prepaid expenses		(4,171	)		8,793
Accounts payable		72,433			(247,063	)
	$	(20,397	)	$	1,362

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Commitments

9 Months Ended

Jun. 30, 2017

Commitments [Abstract]

COMMITMENTS

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 $11,559 per month (Cdn $15,000 per month). As of June 30, 2017, 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 on 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 $
2017 Q4 (July - September)	$	–	$	–
2018 Q1 (October - December)	$	6,141	$	7,969
2018 Q2 (January - March)	$	6,141	$	7,969
2018 Q3 (April - June)	$	6,141	$	7,969
2018 Q4 (July - September)	$	6,141	$	7,969
2019 Q1 (October - December)	$	6,141	$	7,969
2019 Q2 (January - March)	$	6,141	$	7,969
2019 Q3 (April - June)	$	6,141	$	7,969

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Subsequent Events

9 Months Ended

Jun. 30, 2017

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

12. SUBSEQUENT EVENTS

In August of 2017, the Company participated in a well on the Company’s Sawn Lake properties. The well was drilled to a total depth of 681 meters. The results of this core well were used for an application for continuation of the mineral rights on one of the Company’s oil sands leases.

On November 21, 2017, the Company’s joint venture partner and operator of two jointly held oil sands leases, where the Company has working interests, submitted two continuation applications to the Alberta Oil Sands Tenure division to apply to continue two oil sands leases that were set to expire on July 10, 2018. On January 29, 2018, the Company’s joint venture partner received approval from Alberta Energy, under the Alberta Oil Sands Tenure Regulation, to continue 2,816 gross hectares (704 hectares net to the Company) of lands, with a non-producing status, effective July 10, 2018. These two continued leases have no future expiry dates but are subject to yearly escalating rental payments until they are deemed to be producing leases.

On December 15, 2017, the Alberta Energy Regulator (“AER”) approved the previously submitted expansion application of the Company’s joint SAGD Project. The amended application sought approval to expand the existing SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be operating to achieve this production level. While the joint venture has not yet approved to expand the SAGD Project, currently, the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake. First production from the SAGD Project began on September 16, 2014. As a result of the low-price environment for bitumen in 2015 and early 2016, a majority of the Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016.

On February 15, 2018, the Company participated in a well on one of its oil sands leases to acquire cores and logs through the Bluesky formation. The Company is currently analyzing the cores and logs.

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Summary of Significant Accounting Policies (Policies)

9 Months Ended

Jun. 30, 2017

Summary of Significant Accounting Policies [Abstract]

Basis of Consolidation

Basis of Consolidation

These 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

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 30, 2017, 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

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 30, 2017 and September 30, 2016, asset retirement obligations amount to $470,230 and $452,533, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.

Financial, Concentration and Credit Risk

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 30, 2017, the Company has approximately $525,474 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 30, 2017 the Company recorded no oil sales, however and for the year ended September 30, 2016, the Company has recorded oil sales received from the operator of the Company’s producing properties. The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s joint venture partner who sells all of the Company’s oil production to 11 purchasers in the oil and gas industry. The Company does not require collateral and management periodically evaluates the operator’s financial statements and the collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and that the risk of loss is minimal.

Basic and Diluted Net Income (Loss) Per Share

Basic and Diluted Net Income (Loss) Per Share

Basic net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were 11,530,000 potentially dilutive securities excluded from the the diluted earnings per share calculation because their effect would be antidilutive.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

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

The Company does not expect the adoption of any other recent accounting pronouncements to have a material impact on the Company’s financial statements.

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Oil and Gas Properties (Tables)

9 Months Ended

Jun. 30, 2017

Oil and Gas Properties [Abstract]

Summary of net payments due under lease rental commitment

	(USD $)		(Cdn $)
2017	$	9,303	$	12,073
2018	$	32,069	$	41,615
2019	$	20,823	$	27,022
2020	$	20,823	$	27,022
2021	$	19,788	$	25,678
Subsequent	$	177,539	$	230,388

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Capitalization of Costs Incurred in Oil and Gas Activities (Tables)

9 Months Ended

Jun. 30, 2017

Capitalization of Costs Incurred in Oil and Gas Activities [Abstract]

Summary of capitalized costs relating to oil producing activities

	June 30,  2017			September 30,  2016
Unproved Oil and Gas Properties	$	21,347,636		$	21,238,052
Proved Oil and Gas Properties		–			–
Accumulated Depreciation and Depletion		(81,993	)		(73,637	)
Net Capitalized Cost	$	21,265,643		$	21,164,415

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Exploration Activities (Tables)

9 Months Ended

Jun. 30, 2017

Exploration Activities [Abstract]

Summary of costs incurred in the oil property acquisition, exploration and development activities

	June 30,  2017		September 30, 2016
Acquisition of Properties:
Proved	$		$
Unproved	$	109,584	$	194,037
Exploration costs	$	10,960	$	39,658
Development costs	$		$

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Asset Retirement Obligations (Tables)

9 Months Ended

Jun. 30, 2017

Asset Retirement Obligations [Abstract]

Schedule of changes to the asset retirement obligation

	June 30, 2017		September 30, 2016
Balance, beginning of period	$	452,533	$	426,607
Liabilities incurred		–		–
Effect of foreign exchange		5,218		9,771
Disposal		–		–
Accretion expense		12,479		16,155
Balance, end of period	$	470,230	$	452,533

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Common Stock (Tables)

9 Months Ended

Jun. 30, 2017

Common Stock [Abstract]

Summary of warrant activity

	Number of Warrants			Weighted Average Exercise Price		Intrinsic Value
Balance, September 30, 2016		52,155,221		$	0.105	$	–
Expired at November 23, 2016		(52,155,221	)		0.105		–
Balance, June 30, 2017		–		$	–	$	–
Outstanding Warrants, June 30, 2017		–		$	–	$	–

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Stock Options (Tables)

9 Months Ended

Jun. 30, 2017

Stock Options [Abstract]

Summary of stock options

	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
$0.05 at June 30, 2017		3,450,000		0.97		0.05		3,450,000		0.05
$0.30 at June 30, 2017		250,000		1.33		0.30		250,000		0.30
$0.34 at June 30, 2017		450,000		1.43		0.34		450,000		0.34
$0.38 at June 30, 2017		6,780,000		2.22		0.38		6,780,000		0.38
$0.23 at June 30, 2017		600,000		2.38		0.23		600,000		0.23
		11,530,000		1.81	$	0.27		11,530,000	$	0.27

Summary of stock option activity

	Number of Underlying Shares		Weighted Average Exercise Price		Weighted Average Fair Market Value
Balance, September 30, 2016		11,530,000	$	0.27	$	0.22
Balance, June 30, 2017		11,530,000	$	0.27	$	0.22
Exercisable, June 30, 2017		11,530,000	$	0.27	$	0.22

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Changes in Non-Cash Working Capital (Tables)

9 Months Ended

Jun. 30, 2017

Changes in Non-Cash Working Capital [Abstract]

Summary of changes in non-cash working capital

	Nine months ended			Nine months Ended
	June 30, 2017			June 30, 2016
Accounts receivable	$	(88,659	)	$	239,632
Prepaid expenses		(4,171	)		8,793
Accounts payable		72,433			(247,063	)
	$	(20,397	)	$	1,362

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Commitments (Tables)

9 Months Ended

Jun. 30, 2017

Commitments [Abstract]

Summary of quarterly payments due under rental agreement

	USD $		Cdn $
2017 Q4 (July - September)	$	–	$	–
2018 Q1 (October - December)	$	6,141	$	7,969
2018 Q2 (January - March)	$	6,141	$	7,969
2018 Q3 (April - June)	$	6,141	$	7,969
2018 Q4 (July - September)	$	6,141	$	7,969
2019 Q1 (October - December)	$	6,141	$	7,969
2019 Q2 (January - March)	$	6,141	$	7,969
2019 Q3 (April - June)	$	6,141	$	7,969

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Nature of Business and Basis of Presentation (Details) - $ / shares	Jun. 30, 2017	Sep. 30, 2016
Nature of Business and Basis of Presentation (Textual)
Common stock, par value	$ 0.001	$ 0.001

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Summary of Significant Accounting Policies (Details) - USD ($)	9 Months Ended
	Jun. 30, 2017	Sep. 30, 2016
Summary of Significant Accounting Policies (Textual)
Asset retirement obligations	$ 470,230	$ 452,533
Financial, concentration and credit risk, description	The Company's joint venture partner is the operator of the Company's producing properties and it is the Company's joint venture partner who sells all of the Company's oil production to 11 purchasers in the oil and gas industry.
Antidilutive securities excluded from computation of earnings	11,530,000
Excess of deposit insurance limits	$ 525,474
Full Cost Method	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 30, 2017, no ceiling test write-downs were recorded for the Company's oil and gas properties.

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Oil and Gas Properties (Details) - Jun. 30, 2017	USD ($)	CAD ($)
Oil and Gas Properties [Abstract]
2017	$ 9,303	$ 12,073
2018	32,069	41,615
2019	20,823	27,022
2020	20,823	27,022
2021	19,788	25,678
Subsequent	$ 177,539	$ 230,388

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Oil and Gas Properties (Details Textual)	9 Months Ended
	Jun. 30, 2017 a oil
Oil and Gas Properties (Textual)
Gas and oil area, gross | a	43,015
Gas and oil area, net | a	34,096
Total number of oil sands leases	9
Land One [Member]
Oil and Gas Properties (Textual)
Lease agreements, expiration date	Jul. 10, 2018
Number of oil sands leases	5
Land Two [Member]
Oil and Gas Properties (Textual)
Lease agreements, expiration date	Aug. 19, 2019
Number of oil sands leases	3
Land Three [Member]
Oil and Gas Properties (Textual)
Lease agreements, expiration date	Apr. 09, 2024
Number of oil sands leases	1

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Capitalization of Costs Incurred in Oil and Gas Activities (Details) - USD ($)	Jun. 30, 2017	Sep. 30, 2016
Summary of capitalized costs relating to oil and gas producing activities
Unproved Oil and Gas Properties	$ 21,347,636	$ 21,238,052
Proved Oil and Gas Properties
Accumulated Depreciation and Depletion	(81,993)	(73,637)
Net Capitalized Cost	$ 21,265,643	$ 21,164,415

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Capitalization of Costs Incurred in Oil and Gas Activities (Details Textual) - USD ($)	9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Capitalization of Costs Incurred in Oil and Gas Activities (Textual)
Depreciation and depletion expense	$ 8,356	$ 8,489

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Exploration Activities (Details) - USD ($)	9 Months Ended	12 Months Ended
	Jun. 30, 2017	Sep. 30, 2016
Acquisition of Properties:
Proved
Unproved	109,584	194,037
Exploration costs	10,960	39,658
Development costs

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Significant Transactions with Related Parties (Details) - USD ($)	9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Sep. 30, 2016
Significant Transactions with Related Parties (Textual)
Accounts payable - related parties	$ 6,403		$ 2,469
Percentage of outstanding common capital stock	53.63%
Professional fees to related party	$ 104,031	$ 101,358

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Asset Retirement Obligations (Details) - USD ($)	9 Months Ended	12 Months Ended
	Jun. 30, 2017	Sep. 30, 2016
Asset Retirement Obligations [Abstract]
Balance, beginning of period	$ 452,533	$ 426,607
Liabilities incurred
Effect of foreign exchange	5,218	9,771
Disposal
Accretion expense	12,479	16,155
Balance, end of period	$ 470,230	$ 452,533

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Asset Retirement Obligations (Details Textual) - USD ($)	9 Months Ended
	Jun. 30, 2017	Sep. 30, 2016
Asset Retirement Obligations (Textual)
Estimate of undiscounted cash flows related to asset retirement obligation	$ 622,818	$ 616,191
Fair value of liability	$ 470,230	$ 452,533
Risk free rate	3.74%
Inflation rate	2.00%
Term of settlement of the obligation	26 years

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Common Stock (Details) - Warrants [Member]	9 Months Ended
	Jun. 30, 2017 $ / shares shares
Summary of warrant activity
Number of Warrants, Beginning Balance | shares	52,155,221
Number of Warrants, Expired | shares	(52,155,221)
Number of Warrants, Ending Balance | shares
Number of Warrants, Outstanding Warrants | shares
Weighted Average Exercise Price, Beginning Balance	$ 0.105
Weighted Average Exercise Price, Expired	0.105
Weighted Average Exercise Price, Ending Balance
Weighted Average Exercise Price, Outstanding Warrants
Intrinsic Value, Beginning Balance
Intrinsic Value, Expired
Intrinsic Value, Ending Balance
Intrinsic Value, Outstanding Warrants

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Common Stock (Details Textual) - USD ($)	1 Months Ended
	Nov. 23, 2016	Jun. 30, 2017	Sep. 30, 2016
Common Stock (Textual)
Common stock, shares outstanding		229,374,605	229,374,605
Historical fair market value of warrant			$ 3,153,216
Warrants [Member]
Common Stock (Textual)
Number of Warrants Expired	52,155,221
Warrants outstanding			52,155,221

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Stock Options (Details) - Stock Options [Member]	9 Months Ended
	Jun. 30, 2017 $ / shares shares
Summary of stock options
Shares Underlying Options Outstanding | shares	11,530,000
Shares Underlying Options Outstanding, Weighted Average Remaining Contractual Life	1 year 9 months 22 days
Shares Underlying Options Outstanding, Weighted Average Exercise Price | $ / shares	$ 0.27
Shares Underlying Options Exercisable | shares	11,530,000
Shares Underlying Options Exercisable, Weighted Average Exercise Price | $ / shares	$ 0.27
$0.05 at June 30, 2017 [Member]
Summary of stock options
Shares Underlying Options Outstanding | shares	3,450,000
Shares Underlying Options Outstanding, Weighted Average Remaining Contractual Life	11 months 19 days
Shares Underlying Options Outstanding, Weighted Average Exercise Price | $ / shares	$ 0.05
Shares Underlying Options Exercisable | shares	3,450,000
Shares Underlying Options Exercisable, Weighted Average Exercise Price | $ / shares	$ 0.05
$0.30 at June 30, 2017 [Member]
Summary of stock options
Shares Underlying Options Outstanding | shares	250,000
Shares Underlying Options Outstanding, Weighted Average Remaining Contractual Life	1 year 3 months 29 days
Shares Underlying Options Outstanding, Weighted Average Exercise Price | $ / shares	$ 0.30
Shares Underlying Options Exercisable | shares	250,000
Shares Underlying Options Exercisable, Weighted Average Exercise Price | $ / shares	$ 0.30
$0.34 at June 30, 2017 [Member]
Summary of stock options
Shares Underlying Options Outstanding | shares	450,000
Shares Underlying Options Outstanding, Weighted Average Remaining Contractual Life	1 year 5 months 5 days
Shares Underlying Options Outstanding, Weighted Average Exercise Price | $ / shares	$ 0.34
Shares Underlying Options Exercisable | shares	450,000
Shares Underlying Options Exercisable, Weighted Average Exercise Price | $ / shares	$ 0.34
$0.38 at June 30, 2017 [Member]
Summary of stock options
Shares Underlying Options Outstanding | shares	6,780,000
Shares Underlying Options Outstanding, Weighted Average Remaining Contractual Life	2 years 2 months 19 days
Shares Underlying Options Outstanding, Weighted Average Exercise Price | $ / shares	$ 0.38
Shares Underlying Options Exercisable | shares	6,780,000
Shares Underlying Options Exercisable, Weighted Average Exercise Price | $ / shares	$ 0.38
$0.23 at June 30, 2017 [Member]
Summary of stock options
Shares Underlying Options Outstanding | shares	600,000
Shares Underlying Options Outstanding, Weighted Average Remaining Contractual Life	2 years 4 months 17 days
Shares Underlying Options Outstanding, Weighted Average Exercise Price | $ / shares	$ 0.23
Shares Underlying Options Exercisable | shares	600,000
Shares Underlying Options Exercisable, Weighted Average Exercise Price | $ / shares	$ 0.23

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Stock Options (Details 1) - Stock Options [Member] - $ / shares	Jun. 30, 2017	Sep. 30, 2016
Summary of company's stock options
Number of Underlying Shares, Balance	11,530,000	11,530,000
Weighted Average Exercise Price, Balance	$ 0.27	$ 0.27
Weighted Average Fair Market Value, Balance	$ 0.22	$ 0.22
Number of Underlying Shares, Exercisable	11,530,000
Weighted Average Exercise Price, Exercisable	$ 0.27
Weighted Average Fair Market Value, Exercisable	$ 0.22

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Stock Options (Details Textual) - USD ($)	9 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Sep. 30, 2016
Stock Options (Textual)
Share-based compensation	$ 2,314	$ 185,903	$ 237,971
Stock Options [Member]
Stock Options (Textual)
Aggregate intrinsic value of exercisable options
Stock option outstanding unvested			200,000

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Changes in Non-Cash Working Capital (Details) - USD ($)	9 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Summary of changes in non-cash working capital
Accounts receivable	$ (88,659)	$ 239,632
Prepaid expenses	(4,171)	8,793
Accounts payable	72,433	(247,063)
Net changes in non-cash working capital (Note 10)	$ (20,397)	$ 1,362

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Commitments (Details) - Jun. 19, 2017 - Rental Agreement [Member]	USD ($)	CAD ($)
2017 Q4 (July - September) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due
2018 Q1 (October - December) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	6,141	7,969
2018 Q2 (January - March) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	6,141	7,969
2018 Q3 (April - June) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	6,141	7,969
2018 Q4 (July - September) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	6,141	7,969
2019 Q1 (October - December) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	6,141	7,969
2019 Q2 (January - March) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	6,141	7,969
2019 Q3 (April - June) [Member]
Summary of annual payments under office lease agreement
Quarterly payments due	$ 6,141	$ 7,969

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Commitments (Details Textual) - Chief Financial Officer [Member] - Concorde Consulting [Member]	9 Months Ended
	Jun. 30, 2017 USD ($)	Jun. 30, 2017 CAD ($)
Commitments (Textual)
Officer ownership of consulting company	100.00%	100.00%
Compensation paid per month to Executive Officer Consulting Company	$ 11,559	$ 15,000

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Subsequent Events (Details)

1 Months Ended

Dec. 15, 2017

Jan. 29, 2018

Aug. 31, 2017

Forecast [Member]

Subsequent Events (Textual)

Joint venture partner received approval

The Company’s joint venture partner received approval from Alberta Energy, under the Alberta Oil Sands Tenure Regulation, to continue 2,816 gross hectares (704 hectares net to the Company) of lands, with a non-producing status, effective July 10, 2018.

SAGD Project Expansion AER Approval

The amended application sought approval to expand the existing SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be operating to achieve this production level. While the joint venture has not yet approved to expand the SAGD Project, currently, the SAGD Project continues to move forward with engineering and identification of long lead time items towards potential expansion to 3,200 bopd and future development at Sawn Lake.

Subsequent Events [Member]

Subsequent Events (Textual)

Well was drilled to a total depth of meters

681