DEEP WELL OIL & GAS INC - Quarter Report: 2016 December (Form 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 December 31, 2016

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)

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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

Condensed Consolidated Balance Sheets

December 31, 2016 and September 30, 2016

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

For the Three Months Ended December 31, 2016 and 2015

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Condensed Consolidated Statements of Cash Flows

For the Three Months Ended December 31, 2016 and 2015

See accompanying notes to the condensed consolidated financial statements

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

(Unaudited)

Notes to the Condensed Consolidated Financial Statements

December 31, 2016

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.

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 December 31, 2016, 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 December 31, 2016, and September 30, 2016, asset retirement obligations amount to $446,220 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 December 31, 2016, the Company has approximately $644,382 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 December 31, 2016 the Company recorded no oil sales, however 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 August 2015, the FASB issued ASU 2015-14, “Revenue from Contracts with Customers (Topic 606) — Deferral of the Effective Date.” ASU 2015-14 defers the effective date of ASU 2014-09 by one year to annual reporting periods beginning after December 15, 2017 with early adoption permitted for periods beginning after December 15, 2016. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements.

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.

The Company’s oil sands acreage as of December 31, 2016, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:

Lease Rental Commitments

The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The 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 December 31, 2016, 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:

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 December 31, 2016.

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

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

The following table illustrates capitalized costs relating to oil producing activities for the three months ended December 31, 2016 and the fiscal year ended September 30, 2016:

Depreciation and depletion expense for the three months ended December 31, 2016 and 2015 were $2,785 and $2,853 respectively.

The following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the three months ended December 31, 2016 and the fiscal year ended September 30, 2016:

Accounts payable – related parties was $3,214 as of December 31, 2016 (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 December 31, 2016, officers, directors, their families, and their controlled entities have acquired 53.63% of the Company’s outstanding common capital stock. This percentage does not include unexercised warrants or stock options.

The Company incurred expenses $33,516 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 December 31, 2016 (December 31, 2015 - $33,714). These amounts were fully paid as of December 31, 2016.

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs as determined by the Alberta Energy Regulator to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At December 31, 2016, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $601,966 (September 30, 2016 - $616,191). The fair value of the liability at December 31, 2016 is estimated to be $446,220 (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:

Common Stock Issued and Outstanding

As of December 31, 2016, 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 December 31, 2016, the Company had no outstanding warrants.

The following is a summary of warrant activity for the period ended December 31, 2016:

There were no warrants outstanding as of December 31, 2016 (September 30, 2016 – there were 52,155,221 warrants outstanding, which had a historical fair market value of $3,153,216).

For the period ended December 31, 2016, 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 December 31, 2016, 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.

The aggregate intrinsic value of exercisable options as of December 31, 2016, was $Nil (September 30, 2016 - $Nil).

The following is a summary of stock option activity as at December 31, 2016:

There were no remaining unvested stock options outstanding as of December 31, 2016 (September 30, 2016 – 200,000).

Compensation to Directors

Concorde Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for $11,172 per month (Cdn $15,000 per month). As of December 31, 2016, the Company did not owe Concorde Consulting any of this amount.

Rental Agreement

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

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:

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 Steam Assisted Gravity Drainage Demonstration Project (the “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.

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 3, 2018, the daily rate of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.7805 as reported by the Bank of Canada. The following table sets forth the rates of exchange for the Cdn$, 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 rates of exchange for such periods as reported by the Bank of Canada.

General Overview

Deep Well Oil & Gas, Inc., along with its subsidiaries through which it conducts business, is an independent junior oil sands exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing oil sands land base where we have working interests ranging from 25% to 100% in the Peace River oil sands area of Alberta, Canada. Our principal office is located at Suite 700, 10150 - 100 Street, 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:

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 revenue for the three month period ending December 31, 2016. For the comparable three month period ending December 31, 2015, oil revenue totaled $120,991 before deduction of royalties. For the three month period ending December 31, 2015, the volume of oil delivered was 9,612 barrels net to our Company, before royalties, with an average oil sales price of $12.59 per barrel ($16.80 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 December 31, 2016, our general and administrative expenses decreased by $172,743 compared to the three months ended December 31, 2015, which was primarily due to (i) a decrease of $66,340 in non-cash share-based compensation charged to expense; (ii) a decrease of $36,824 in engineering fees; and (iii) a decrease of foreign exchange loss of $13,793. We also received $90,000 for the three month period ending December 31, 2016 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 $137,358 for the three months ended December 31, 2016 compared to $199,401 for the three months ended December 31, 2015.

For the three months ended December 31, 2016, our depreciation, depletion, and accretion expense decreased by $2,267 compared to the three months ended December 31, 2015, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition. No significant asset purchases were made in the quarter ended December 31, 2016.

For the three months ended December 31, 2016, there were no significant increases or decreases for rental and other income or interest income compared to the three months ended December 31, 2015.

As a result of the above transactions, we recorded a decrease of $172,146 in our net loss and loss from operations for the three months ended December 31, 2016 compared to the three months ended December 31, 2015. As discussed above, this decrease was primarily due to decreases in non-cash share-based compensation expenses, engineering fees, and foreign exchange loss.

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). A majority of our Company’s Joint Venture partners voted to temporarily suspend operations of the SAGD Project at the end of February 2016.

The current SAGD Project has:

The first SAGD well pair, for the SAGD Project, was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection commenced in May 2014 and production started in September of 2014. Production from this one SAGD well pair and increased significantly over the 18-month period it produced. In January and February of 2016 production from the SAGD Project reached a steady state averaging 615 bopd, on a 100% basis (154 bopd net to us), with an average SOR of 2.1 from one SAGD well pair. It is expected that a reactivation of the existing SAGD Project facility and current SAGD well pair will be part of the potential commercial expansion along with the previously AER approved second SAGD well pair. In early May of 2016, an amended application was submitted to the AER for an expansion of the existing SAGD Project facility site which would potentially increase the operation for up to a total of eight SAGD well pairs. The amended application sought approval to expand the current SAGD Project facility site to 3,200 bopd (100% basis). It is anticipated that only five SAGD well pairs need to be operating to achieve this production level. The expanded facility will be designed to handle up to 3,200 bopd. The AER approval for the expansion of the existing SAGD Project was granted on December 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.

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 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 December 31, 2016, our total assets were $23,119,285 compared to $23,166,967 as of September 30, 2016. This decrease of $47,682 in our total assets was primarily due to cash used for general and administrative expenses, offset by a decrease of accounts receivable.

Our total liabilities as of December 31, 2016 were $491,219 compared to $502,508 as of September 30, 2016. There was no significant change in our total liabilities from the September 30, 2016 year end.

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

As of December 31, 2016, we had working capital of $1,364,714 compared to a working capital of $1,406,475 as of September 30, 2016. This decrease of $41,761 in working capital is the result of the net change of total assets as described above. Currently, we have no long-term third party debt other than our estimated asset retirement obligations on oil and gas properties.

As reported on our condensed Consolidated Statement of Cash Flows under “Operating Activities”, for the three months ended December 31, 2016, our net cash used from operating activities was $78,511 compared to $590,832 cash inflow as of December 31, 2015. This decrease of $512,321 in our operating activities was primarily the result of $453,180 transferred and held in trust for a potential acquisition which was not concluded and was subsequently returned to us in May of 2016.

As reported on our condensed Consolidated Statement of Cash Flows under “Investing Activities”, we had a decrease of $6,578 on investment in our oil and gas properties for the three months ended December 31, 2016 compared to the three months ended December 31, 2015. There were no significant investing activities during these periods.

As reported on our condensed Consolidated Statement of Cash Flows under “Financing Activities”, for the three months ended December 31, 2016 and December 31, 2015, there was no cash inflow or outflow in financing activities.

Our cash and cash equivalents as of December 31, 2016 was $1,301,989 compared to $1,181,790 for the quarter ended December 31, 2015. This decrease of $120,199 in cash was primarily due to general and administrative expenses. Currently, we have 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:

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

The preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description of risks and uncertainties, see the sections 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.

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.

Disclosure Controls and Procedures

As of the end of our fiscal quarter ended December 31, 2016, 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 December 31, 2016, 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 December 31, 2016, 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

None.

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.

None.

None.

Not applicable.

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 December 31, 2016.

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 December 31, 2016.

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.