DEEP WELL OIL & GAS INC - Quarter Report: 2014 December (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended December 31, 2014

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 ☐

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 ☐

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.

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

The number of shares of common stock outstanding as of February 23, 2015 was 229,374,605.

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

Condensed Consolidated Balance Sheets

December 31, 2014 and September 30, 2014

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, 2014 and 2013

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, 2014 and 2013

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, 2014

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 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, 2014.

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, 2014.

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.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

The Company determines allowances for doubtful accounts based on aging of specific accounts. Accounts receivable are stated at the historical carrying amounts net of allowances for doubtful accounts and include only the amounts the Company deems to be collectable. The allowance for bad debts was $nil and $nil at December 31, 2014 and September 30, 2014, respectively.

Crude oil and natural gas properties

The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.

Under the successful efforts method of accounting, the Company capitalizes exploratory drilling, equipping and facility costs on the balance sheet pending determination of whether the project has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are assigned to a project, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found in a project, the capitalized costs associated with the project are expensed, net of any salvage value. Total capitalized costs pending the determination of proved reserves were $19.6 million and $19.6 million at December 31, 2014 and September 30, 2014, respectively.

Property and Equipment

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

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

Long-Lived Assets

Oil and Gas Properties - Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate.

Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.

Non Oil and Gas Assets - The Company reviews for the impairment of long-lived assets annually and whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss would be recognized when estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition is less than its carrying amount. Impairment is measured as the amount by which the assets’ carrying value exceeds its fair value. No impairments to the Company’s long-lived assets were identified or recorded in the three months ended December 31, 2014 or in the fiscal year ended September 30, 2014.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed crude oil and natural gas reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.

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 at December 31, 2014 and September 30, 2014, asset retirement obligations amount to $454,223 and $469,013, respectively. The Company has posted bonds, where required, with the Government of Alberta based on the amount the government estimates the cost of abandonment and reclamation to be.

Foreign Currency Translation

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

Accounting Method

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

Dividend Policy

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

Financial, Concentration and Credit Risk

The Company does not have any concentration or related financial credit risk related to cash as most of the Company’s funds are maintained in a financial institution which has its deposits fully guaranteed by the Government of Alberta.

The Company is not directly subject to credit risk resulting from the concentration of its crude oil sales. For the period ending December 31, 2014 and for the year ended September 30, 2014, the Company has recorded oil sales received from the operator of the Company’s producing properties. The Company’s joint venture partner is the operator of the Company’s producing properties and it is the Company’s joint venture partner who sells 100% of the Company’s oil production to two or more purchasers in the oil and gas industry. The Company does not require collateral and management periodically evaluates the operator’s financial statements and the collectability of oil sales receivables from the operator and believes that the Company’s oil sales receivables are fully collectable and that the risk of loss is minimal.

Income Taxes

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

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

Revenue Recognition

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

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

Advertising and Market Development

The Company expenses advertising and market development costs as incurred.

Basic and Diluted Net Income (Loss) Per Share

Basic net income (loss) per share amounts are computed based on the weighted average number of shares actually outstanding. Diluted net income (loss) per share amounts are computed using the weighted average number of common shares and common equivalent shares outstanding as if shares had been issued on the exercise of the common share rights, unless the exercise becomes antidilutive and then the basic and diluted per share amounts are the same. There were 23,543,809 common stock equivalents excluded from the calculation because their effect would be antidilutive.

Financial Instruments

Financial instruments include cash and cash equivalents, accounts receivable, long term investments, investment in equity securities, accounts payable and accounts payable - related parties. The fair value of these financial instruments approximates their carrying value because of the short-term maturity of these items unless otherwise noted. The fair value of the investment in equity securities cannot be determined as the market value is not readily obtainable. The equity securities are reported using the cost method.

Environmental Requirements

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

Share-Based Compensation

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

Recently Adopted Accounting Standards

In June 2014, the FASB issued ASU 2014-10, “Development Stage Entities (Topic 915): Elimination of Certain Financial Reporting Requirements, Including an Amendment to Variable Interest Entities Guidance in Topic 810, Consolidation”. The guidance eliminates the definition of a development stage entity thereby removing the incremental financial reporting requirements from U.S. GAAP for development or exploration stage entities, primarily presentation of inception to date financial information. The provisions of the amendments are effective for annual reporting periods beginning after December 15, 2014, and the interim periods therein. However, early adoption is permitted. Accordingly, the Company has adopted this standard as of September 30, 2014.

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

Estimates and Assumptions

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

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

The Company’s oil sands acreage as of December 31, 2014, 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:

Effective September 25, 2014, the Company, through its subsidiary Deep Well Alberta, entered into a Purchase and Sale agreement with Classic Energy Inc. (“Classic”), pursuant to which the Company acquired Classic’s 20% working interest in five sections in one Sawn Lake oil sands lease where the Company already owned working interests. As of September 25, 2014, the Company increased its net acres in the Sawn Lake oil sands properties from 33,463 to 34,096 net acres.

Lease Rental Commitments

The Company has acquired interests in certain oil sands properties located in North Central Alberta, Canada. The terms include certain commitments related to oil sands properties that require the payments of rents as long as the leases are non-producing. As of December 31, 2014, the Company’s net payments due under this commitment are as follows:

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

The Company plans to meet the second of these conditions. As at December 31, 2014 and September 30, 2014, the Company has an interest in ten wells, which can be counted towards these requirements.

The Company has identified two other wells drilled on these leases, which may be included in the satisfaction of this requirement. The Company has also acquired and processed 25 miles of seismic on the leases, which can be counted towards these requirements. Our joint venture partner and operator of the SAGD Project has also acquired additional seismic that can be used towards our MLE requirements.

The Company follows the successful efforts method of accounting for costs of oil properties. Under this method, only those exploration and development costs that relate directly to specific oil reserves are capitalized; costs that do not relate directly to specific reserves are charged to expense. Producing, non-producing and unproven properties are assessed annually, or more frequently as economic events indicate, for potential impairment.

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 impairment on a field-by-field basis. No impairment losses were recognized for the period ended December 31, 2014 (September 30, 2014 - $nil).

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.

Steam Assisted Gravity Drainage Demonstration Project

On July 30, 2013, the Company entered into a Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”) to jointly participate in an Alberta Energy Regulator (“AER”) approved SAGD Project on one section of land where the Company now has a 25% working interest (after the execution of the Farmout Agreement as defined below). The SAGD Project is located on section 30-91-12W5 of the Company’s Peace River oil sands properties located in North Central Alberta, Canada (also known as the Sawn Lake heavy oil reservoir). On August 15, 2013, and in accordance with the SAGD Project Agreement and the Amendment, the Company served notice (“Notice of Election”) to of the operator of the Company’s election to participate in the SAGD Project. Upon signing the Notice of Election the Company was required to pay in full the cash calls for the Company’s initial share of the costs of the SAGD Project and in accordance with a Farmout Agreement dated July 31, 2013 the Company has since paid all cash calls in full to the operator of the SAGD Project.

Farmout Agreement

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

SAGD Project – Phase 1

The SAGD Project started with the first phase (“Phase 1”) consisting of the drilling and completion of one SAGD well pair, the construction of a facility for steam generation, water handling and oil treating, plus water source and disposal facilities. As required by the Farmout Agreement, the Farmee has since paid Cdn $19,355,129 to the operator of the SAGD Project for the Farmee’s share and the Company’s share of the costs of the SAGD Project up to December 31, 2014. The total SAGD Project capital costs for Phase 1 plus additions have been estimated by the operator to be Cdn $36.9 million.

SAGD Project – Phase 2

On June 27, 2014, the Company paid a Cdn $300,000 cash call to the operator for the proposed Phase 2 front end costs for the SAGD Project. The Phase 2 front end costs include work on preliminary engineering design, regulatory approval, environmental approval work and determining regulatory requirements sufficient to define the work program, schedule and estimated cost of this second phase which is anticipated to include the drilling of two additional SAGD well pairs and the associated expansion of the current SAGD steam plant. The Farmee reimbursed the Company in the amount of Cdn $300,000 as per the Farmout Agreement dated July 31, 2013.

Water Rights Conveyance Agreement

On October 9, 2013, and in connection to the SAGD Project agreement dated July 30, 2013, the Company entered into a Water Rights Conveyance Agreement whereby the Company acquired a 25% working interest in one water source well and one water disposal well for a cost of Cdn $384,046, which in turn was reimbursed to the Company by the Farmee. Also pursuant to the Water Rights Conveyance Agreement dated October 9, 2013 and the SAGD Project agreement dated July 30, 2013, the Company was issued a cash call in the amount of Cdn $1,058,568 for the expenditures relating to the water source well, water disposal well and pipelines to connect them to the SAGD Project surface facility. The Farmee has since paid this cash call in the amount of Cdn $1,058,568 pursuant to the Farmout Agreement dated July 31, 2013.

Acquisition of Royalty Interests

On March 18, 2014 and June 27, 2014, the Company, through its 100% wholly owned subsidiary company Northern Alberta Oil Ltd., entered into and subsequently closed two Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and Transfer Agreements (collectively the “Agreements”), with the Company’s joint venture partner (“JV Partner”) and one related party (Mr. Malik Youyou), whereby the Company acquired and cancelled 5.5% of a disputed 6.5% overriding royalty claim (the “Purported 6.5% Royalty”) potentially on some lands owned by the Company. The Company’s counsel and vendor’s counsel negotiated the terms and conditions of both the “Acquisition of Royalty Interest” and “General Indenture of Conveyance, Assignment and Transfer” agreements. Although the Company does not confirm the validity of the Purported 6.5% Royalty, the Company determined that it was in the best interests of its shareholders to come to an arrangement to acquire and cancel most of the Purported 6.5% Royalty to prevent a potential encumbrance over its land or the possibility of future litigation resulting from these alleged royalty claims. Pursuant to the terms and conditions of the Agreements to acquire the purported overriding royalty interest claims, the Company paid the following consideration:

The Company accounts for the cost of its oil sands projects and continues to capitalize project costs after the completion of drilling, equipping and facility construction as long as sufficient progress is being made in assessing the oil sands reserves to justify the oil sands project as a producing well.

For the period ended December 31, 2014, the Company’s management determined that sufficient progress has been made in assessing its oil sands reserves for continued capitalization of exploratory drilling, equipping and facility costs. In relation to this sufficient progress assessment of its oil sands project the Company considered among other criteria; long lead times in getting regulatory approval for oil sands thermal recovery projects, road bans, winter access only properties and governmental and environmental regulations which can and often delay development of oil sands projects. Because of these and other factors, the Company’s oil sands project can take significantly longer to complete than regular conventional drilling programs for lighter oil. To date the Company’s geological, engineering, economic studies, and AER approved thermal recovery projects; including the Company’s now producing SAGD Project, continue to lead them to believe that there is continuing progress toward bringing the project to commercial production. Therefore, the Company has continued to capitalize its costs associated with its oil sands project.

For the Company’s oil sands projects, exploratory drilling, equipping and facility costs are capitalized on the balance sheet under “Oil and Gas Properties” line item, pending a determination of whether potentially economic oil sands reserves have been discovered by the drilling effort to justify oil sands project as a producing well. The Company periodically assesses the exploration drilling, equipping and facility capitalized costs for impairment and once a determination is made that a well is of no potential economic value, the costs related to that oil sands project are expensed as dry hole and reported in exploration expense. No impairments to the Company’s long-lived assets were identified or recorded in the three months ended December 31, 2014 or in the fiscal year ended September 30, 2014.

The following table illustrates capitalized costs relating to oil producing activities for the three months ended December 31, 2014 and the fiscal year ended September 30, 2014:

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, 2014 and the fiscal year ended September 30, 2014:

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

As of November 19, 2008, the Company converted its Signet shares into 2,241,558 shares of Andora, which represents an equity interest in Andora of approximately 2.24% as of December 31, 2013, which is Andora’s fiscal year end. These shares are carried at a nominal value using the cost method and their value is included under oil and gas properties on the Company’s balance sheet.

There was $13,757 of depreciation expense for the period ended December 31, 2014 (December 31, 2013 - $18,176).

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

Accounts payable – related parties was $2,090 as of December 31, 2014 (September 30, 2014 - $16,977) 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, 2014, officers, directors, their families, and their controlled entities have acquired 53.41% of the Company’s outstanding common capital stock. This percentage does not include unexercised warrants or stock options.

The Company incurred expenses $39,618 to one related party, Concorde Consulting, for professional fees and consulting services provided to the Company during the period ended December 31, 2014 (September 30, 2014 - $198,703). These amounts were fully paid as of December 31, 2014.

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 to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At December 31, 2014, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $661,520 (September 30, 2014 - $ 689,445). The fair value of the liability at December 31, 2014 is estimated to be $454,223 (September 30, 2014 - $ 469,013) 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 35 years.

Changes to the asset retirement obligation were as follows:

On June 20, 2013, the Company completed a private placement for an aggregate of 850,000 units at a price of $0.05 per unit for an aggregate of $42,500. Each unit consists of one common share and one common share purchase warrant. Each warrant entitles the holder to purchase one additional common share at a price of $0.075 per common share for a period of three years from the date of closing, provided that if the closing price of the common shares of the Company on the principal market on which the shares trade is equal to or exceeds $1.00 for 30 consecutive trading days, the warrant term shall automatically accelerate to the date which is 30 calendar days following the date that written notice has been given to the warrant holders. The warrants expire on June 20, 2016. The value of the common shares and the warrants totalled $27,448 and $15,052, respectively.

On July 31, 2013, the Company completed a private placement for an aggregate of 45,111,778 common shares for an aggregate of $22,000,000. Pursuant to the subscription agreement between the Company and investor the Company issued the shares to the investor after September 20, 2013 but before November 30, 2013. No warrants were issued to the investor in connection with this private placement.

Between August 12 and August 15, 2013, six directors and two consultants of the Company acquired a combined total of 3,768,096 common shares, upon exercising stock options and warrants, at exercise prices ranging from $0.05 to $0.14 per common share for total combined gross proceeds to the Company of $372,000.

Return of Capital Distribution

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

Warrants

On October 10, 2013, the Company extended the expiration date of two warrants to purchase up to an aggregate of 29,047,617 shares of the Company’s common stock. The exercise price of the warrants remains unchanged at $0.105 per share. As a result of this extension, the expiration date of the warrants has been amended from the original expiry date of November 9, 2013 to November 23, 2015.

On June 23, 2014, 47,618 partial warrants were cancelled and transferred to a non-related party. 

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

The following table summarizes the Company’s warrants outstanding as of December 31, 2014:

The following is a summary of warrant activity for the period ended December 31, 2014:

There were 72,377,141 warrants outstanding as of December 31, 2014 (September 30, 2014 – 72,424,759), which have a historical fair market value of $1,738,336 (September 30, 2013 - $1,743,336).

Measurement Uncertainty for Warrants

The Company used the Black-Scholes option pricing model (“Black-Scholes”) to value the options and warrants. This model was developed for use in estimating the fair value of traded “European” options which are liquid and that have no vesting restrictions and are fully transferable. The stock options that are granted to employees and directors and the warrants attached to the units issued by the Company are non-transferable and some vest over time, and all are “American” options. Option pricing models require the input of subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes in the assumptions. The following assumptions are used in the Black-Scholes option-pricing model:

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

Expected Volatility – Expected volatilities are based on historical volatility of the Company’s stock, adjusted where determined by management for unusual and non-representative stock price activity not expected to recur. The expected volatility used ranged from 96% to 116%.

Expected Dividend – The Black-Scholes valuation model calls for a single expected dividend yield as an input. The Company currently pays no dividends and does not expect to pay dividends in the foreseeable future.

Risk-Free Interest rate – The Company bases the risk-free interest rate on the implied yield currently available on U.S. Treasury zero-coupon issues with an equivalent remaining term. The risk-free rate used ranged from 0.62% to 1.31%.

On November 28, 2005, and as amended on December 4, 2014, the Board of Deep Well adopted the Deep Well Oil & Gas, Inc. Stock Option Plan (the “Plan’). The Plan was approved by the majority of shareholders at the February 24, 2010 general meeting of shareholders. The Plan, is administered by the Board, permits options to acquire shares of the Company’s common stock (the “Common Shares”) to be granted to directors, senior officers and employees of the Company and its subsidiaries, as well as certain consultants and other persons providing services to the Company or its subsidiaries.

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

On March 23, 2011, the Company granted six of its directors options to purchase 450,000 shares each of common stock at an exercise price of $0.14 per Common Share, 150,000 vesting immediately and the remaining vesting one-third on March 23, 2012, and one-third on March 23, 2013, with a five-year life.

On June 20, 2013, the Company granted six of its directors options to purchase 450,000 shares each of common stock at an exercise price of $0.05 per Common Share, 150,000 vesting immediately and the remaining vesting one-third on June 20, 2014, and one-third on June 20, 2015, with a five-year life.

On June 20, 2013, the Company granted two consultants an option to purchase each 1,000,000 shares each of common stock at an exercise price of $0.05 per Common Share, 500,000 vesting immediately and remaining vesting on June 20, 2014.

On June 20, 2013, the Company granted one employee an option to purchase 150,000 shares each of common stock at an exercise price of $0.05 per Common Share, 50,000 vesting immediately and the remaining vesting one-third on June 20, 2014, and one-third on June 20, 2015, with a five-year life.

From August 12 to 15, 2013, there were 3,200,000 stock options exercised for total gross proceeds to the Company of $322,000 from six directors and one consultant.

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

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

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

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

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

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

For the period ended December 31, 2014, the Company recorded share based compensation expense related to stock options in the amount of $316,959 (September 30, 2014 – $1,087,356) on the stock options that were issued on November 17, 2014 and vested stock options that were previously granted. As of December 31, 2014, there was remaining unrecognized compensation cost of $1,039,871 related to the non-vested portion of these unit option awards. Compensation expense is based upon straight-line depreciation of the grant-date fair value over the vesting period of the underlying unit option.

The aggregate intrinsic value of exercisable options as of December 31, 2014, was $Nil (September 30, 2014 - $0.11).

The following is a summary of stock option activity as at December 31, 2014:

A summary of the options granted at December 31, 2014 and September 30, 2014 and changes during the periods then ended is presented below:

There were 5,620,000 unvested stock options outstanding as of December 31, 2014 (September 30, 2014 – 5,370,000).

Measurement Uncertainty for Stock Options

The Company used the Black-Scholes option pricing model (“Black-Scholes”) to value the options and warrants. This model was developed for use in estimating the fair value of traded “European” options which are liquid and that have no vesting restrictions and are fully transferable. The stock options that are granted to employees and directors and the warrants attached to the units issued by the Company are non-transferable and some vest over time, and all are “American” options. Option pricing models require the input of subjective assumptions including expected share price volatility. The fair value estimate can vary materially as a result of changes in the assumptions. The following assumptions are used in the Black-Scholes option-pricing model:

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

Expected Volatility – Expected volatilities are based on historical volatility of the Company’s stock, adjusted where determined by management for unusual and non-representative stock price activity not expected to recur. The expected volatility used ranged from 96% to 122%.

Expected Dividend – The Black-Scholes valuation model calls for a single expected dividend yield as an input. The Company currently pays no dividends and does not expect to pay dividends in the foreseeable future.

Risk-Free Interest rate – The Company bases the risk-free interest rate on the implied yield currently available on U.S. Treasury zero-coupon issues with an equivalent remaining term. The risk-free rate used ranged from 0.62% to 1.83%.

Compensation to Directors

Since the acquisition of Northern Alberta Oil Ltd., the Company and Northern have entered into the following contracts with the following companies for the services of their officers:

As consideration for the execution of the Amending Agreement and the Termination of parts of the Prior Agreement, and waiving Cdn $239,528 accrued by the Company as owing to Portwest.

In the December 31, 2014 quarter end period, no fees were owed or paid to Portwest. As of September 30, 2013, the Company had settled all outstanding amounts owed to Portwest.

Rental Agreement

On January 21, 2014, the Company renewed its Edmonton office lease commencing effective on January 1, 2014 and expiring on June 30, 2015. The quarterly payments due are as follows:

IGM Resources Corp vs. Deep Well Oil & Gas, Inc., et al – DISMISSED

On February 11, 2014, the Court dismissed, without any costs to the Company, the Plaintiff’s claims against Deep Well Oil & Gas, Inc. and its subsidiary Northern Alberta Oil Ltd.

On March 10, 2005, I.G.M. Resources Corp. (“the Plaintiff”) filed against Classic Energy Inc., 979708 Alberta Ltd., Deep Well Oil & Gas, Inc., Nearshore Petroleum Corporation, Mr. Steven P. Gawne, Rebekah Gawne, Gawne Family Trust, 1089144 Alberta Ltd., John F. Brown, Diane Lynn McClaflin, Cassandra Doreen Brown, Elissa Alexandra Brown, Brown Family Trust, Priority Exploration Ltd., Northern Alberta Oil Ltd. and Gordon Skulmoski (the “IGM Defendants”) a Statement of Claim in the Court of Queen's Bench of Alberta Judicial District of Calgary. This suit is a part of a series of lawsuits or actions undertaken by the Plaintiff against some of the other above IGM Defendants.

The Plaintiff was and still is a minority shareholder of 979708 Alberta Ltd. ("979708"). 979708 was in the business of discovering, assembling and acquiring oil and gas prospects. In 2002 and 2003, 979708 acquired oil and gas prospects in the Sawn Lake area of Alberta. On or about the 14^th of July, 2003, all or substantially all the assets of 979708 were sold to Classic Energy Inc. The Plaintiff claims the value of the assets sold was far in excess of the value paid for those assets. On April 23, 2004, Northern purchased Classic Energy Inc.'s assets, some of which are under dispute by the Plaintiff. On June 7, 2005, Deep Well acquired all of the common shares of Northern thereby giving Deep Well an indirect beneficial interest in the assets in which the Plaintiff is claiming an interest.

The Plaintiff was seeks an order setting aside the transaction and returning the assets to 979708, compensation in the amount of Cdn $15,000,000, a declaration of trust declaring that Northern and Deep Well hold all of the assets acquired from 979708 and any property acquired by use of such assets, or confidential information of 979708, in trust for the Plaintiff.

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the results of the Company’s operations from oil (in the form of bitumen) producing activities from the Company’s Sawn Lake oil sands properties located in Alberta, Canada, for the period ending December 31, 2014 and for the year ended September 30, 2014:

For the period ending December 31, 2014, the Company reported oil revenue in the amount of $137,420 after deduction of royalties. For the period ending December 31, 2014, the volumes of oil delivered were 3,614 barrels net to the Company, before royalties, with an average oil sales price of $35.84 per barrel (Cdn$41.68 per barrel). Operating expenses are zero since at this time they were paid for under the Farmout Agreement. Transportation costs are included in these operating costs. The total share of the material costs and operating expenses of the Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to the Company of $Nil. As required by the Farmout Agreement, the Farmee has since paid Cdn $19,355,129 to the operator of the SAGD Project for the Farmee’s share and the Company’s share of the costs of the SAGD Project up to December 31, 2014. These costs included the drilling of the SAGD well pair; the purchase and transportation of equipment; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells and expenditures to connect these water wells to the steam plant facility along with a fuel source tie-in; and the monthly operating expenses associated with the steaming and production of the SAGD well pair up to December 31, 2014, 2014.

Capitalized Costs Relating Specifically to the SAGD Project

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

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

See Note 5 herein “Exploration Activities”.

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 the “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, 2014, filed with the Securities and Exchange Commission on January 13, 2015.

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 February 18, 2015, the noon rate of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.8029, as reported by the Bank of Canada. The following table sets forth the rates of exchange for the Cdn$, 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 noon 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 emerging independent junior oil and gas exploration and development company headquartered in Edmonton, Alberta, Canada. Our immediate corporate focus is to develop the existing land base that we presently control in the Peace River oil sands area in 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 OTCQB marketplace under the symbol DWOG. We maintain a website at www.deepwelloil.com. The OTCQB marketplace requires companies to be fully compliant in their filing requirements under the Exchange Act and as of 2014 all companies must now meet the new eligibility standards to trade on OTCQB, which includes but is not limited to (i) payment of an annual fee; and (ii) submission of an annual verification and management certification confirming that the company is current in its reporting requirements. These new requirements are aimed at improving the information available to investors.

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, including the startup of a Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”), where we have a 25% working interest, which began producing on September 16, 2014. The following table sets forth certain financial information along with our first revenue with respect to our operations:

First production of oil in the form of bitumen began on September 16, 2014. For the period ending December 31, 2014, we reported oil revenue in the amount of $146,400 before deduction of royalties. For the period ending December 31, 2014, the volumes of oil delivered were 3,614 barrels net to our Company, before royalties, with an average oil sales price of Cdn$41.68 per barrel. The realized sales price of our oil is discounted for diluent, trucking, pipeline and additional treating costs from the West Texas Intermediate (“WTI”) benchmark price. While there has been a significant decline in oil prices, the Canadian dollar has weakened and offset some of the impact. In addition, our fuel gas costs to operate our SAGD Project steam facility plant have declined similarly to the decline in the WTI benchmark price. Our net operating margin after operating expenses is zero since at this time any negative operating margins are paid for under the farmout agreement we entered into on July 31, 2013 (the “Farmout Agreement”) to fund our share of the SAGD Project. Transportation costs are included in these operating costs. Therefore, the total share of the material costs and operating expenses of our Company’s joint SAGD Project, has been funded in accordance with the Farmout Agreement, at a net cost to our Company of $Nil. As required by the Farmout Agreement, the Farmee (as defined below) has since paid Cdn$19.4 million to the operator of the SAGD Project for the Farmee’s share and our share of the costs of the SAGD Project up to December 31, 2014. These costs included the drilling of the SAGD well pair; the purchase and transportation of equipment; installation and construction of the steam plant facility; testing and commissioning; the purchase of the water source and disposal wells and expenditures to connect these water wells to the steam plant facility along with a fuel source tie-in; and the monthly operating expenses associated with the steaming and production of the SAGD well pair up to December 31, 2014.

For the three months ended December 31, 2014, our general and administrative expenses increased by $122,598 compared to the three months ended December 31, 2013, which was primarily due to (i) an increase of $160,585 in non-cash share based compensation charged to expense, which was mainly due to vested stock options we granted on September 19, 2014 and November 17, 2014 to our directors and contractors; and (ii) an increase in engineering fees for the preparation of an independent reserves evaluation of our Sawn Lake properties. These increases were offset by (i) a decrease of foreign exchange loss of $31,485; and (ii) a decrease in legal fees. We also received $90,000 during this quarter from one of our joint venture partners in accordance with a Farmout Agreement to offset some of our monthly operational expenses. After adjusting for the non-cash items listed above, our general and administrative expenses were $180,558 for the three months ended December 31, 2014 compared to $185,295 for the three months ended December 31, 2013.

For the three months ended December 31, 2014, our depreciation, depletion, and accretion expense decreased by $3,312 compared to the three months ended December 31, 2013, 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, 2014.

For the three months ended December 31, 2014, there were no significant increases or decreases for rental and other income or interest income compared to the three months ended December 31, 2013.

As a result of the above transactions, we recorded an increase of $124,111 in our net loss and comprehensive loss from operations for the three months ended December 31, 2014 compared to the three months ended December 31, 2013. As discussed above, this increase was primarily due to an increase in non-cash share based compensation expenses and engineering fees.

Operations

The first oil production from our SAGD Project commenced on September 16, 2014 from the first SAGD well pair. The SAGD well pair was drilled to a vertical depth of approximately 650 meters with a horizontal length of 780 meters each. Steam injection began in May 2014 and circulated for up to four months with production commencing in mid-September 2014 from the Bluesky oil sands reservoir. The operator along with us and our other joint venture partner intend to evaluate the production levels and steam to oil ratios over the next few months to determine and verify the use of SAGD technology in the Bluesky reservoir. It was recently determined that the drilling of an additional SAGD well pair and the associated expansion of the current SAGD plant facility has been deferred due to the recent decline in oil prices. However, it was also determined that the operator of the SAGD Project will proceed with the Phase 2 front-end work, which includes work on preliminary engineering design, regulatory approvals, environmental approval work and determining regulatory requirements sufficient to define the work program.

On March 18, 2014 and June 27, 2014, through our subsidiary company, Northern, we entered into and subsequently closed two Acquisition of Royalty Interest Agreements and General Indenture of Conveyance, Assignment and Transfer Agreements (collectively “the Agreements”), with one of our joint venture partners (“JV Partner”) and one related party (Mr. Malik Youyou), under which we acquired and cancelled 5.5% of a disputed 6.5% overriding royalty claim (the “Purported 6.5% Royalty”) on certain lands owned by us. Pursuant to the terms and conditions of the Agreements to acquire the purported overriding royalty interest claims, we paid the following consideration:

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

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. This application, submitted in early 2012, was an application to modify our previously approved in-situ demonstration project for a well to test thermal production on our Sawn Lake oil sands leases. This modification changed the vertical cyclic steam stimulation (“CSS”) well earlier approved, into a thermal recovery project to test two wells that use a horizontal application of CSS. We are currently waiting on the production facility performance results from the SAGD Project in order to fine-tune our HCSS project facility design on the half section of land where we plan to drill two horizontal wells to test the use of HCSS technology.

Currently, we have a 90% working interest in 51 sections on six oil sands leases and a 100% working interest in five sections on one oil sands lease in the Peace River oil sands area of Alberta, where we are the operator. In addition, we have a 25% working interest in another 12 sections on two oil sands leases in the Peace River oil sands area of Alberta. These nine oil sands leases are contiguous and cover 43,015 gross acres (17,408 gross hectares). 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. To date, our geological, engineering and economic studies support the conclusion that our working interest can support full commercial production.

Liquidity and Capital Resources

As of December 31, 2014, our total assets were $23,050,761 compared to $23,691,595 as of September 30, 2014. This decrease of $640,834 in our total assets was primarily due to a decrease in our accounts receivable, as a result of a reimbursement of Cdn$1,200,000 from the Farmee in October of 2014 for the SAGD Project winterization program, offset by $383,535 which was previously paid to us, just before our September 30, 2014 year end, by the Farmee for the SAGD Project operating expenses and then subsequently paid by us to the operator in October 2014.

Our total liabilities as of December 31, 2014 were $822,135 compared to $1,200,188 as of September 30, 2014. This decrease of $378,053 in our total liabilities was mainly the result of our payment for outstanding accounts payable to the operator of the SAGD Project for operating expenses, which was $383,535 and which was paid to us under the Farmout Agreement, just before our year end.

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

As of December 31, 2014, we had working capital of $2,425,176 compared to a working capital of $2,687,554 as of September 30, 2014. This decrease is the result of the net change of accounts receivable, offset by the decrease of accounts payable as described above. As of February 23, 2015, we have 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 December 31, 2014, we recorded $307,760 in accounts payable due to the operator for our working interest share of the outstanding operating expenses of the SAGD Project, of which all is reimbursable by the Farmee in accordance with the Farmout Agreement. Therefore, this amount is also recorded in accounts receivable to be paid to us from the Farmee to cover our share of the costs of the SAGD Project.

As reported on our Consolidated Statement of Cash Flows under “Operating Activities”, for the three months ended December 31, 2014, our net cash from operating activities was $85,368. This cash inflow was primarily the result of non-cash working capital related to accounts receivable and accounts payable as disclosed above. For the three months ended December 31, 2013, the net cash used in operating activities was $3,002,774. This decrease in cash flow was primarily due to US$2,435,124 being transferred into a trust account, to exercise the option to purchase interests in the disputed Purported 6.5% Royalty as previously reported in the prior comparable period.

As reported on our Consolidated Statement of Cash Flows under “Investing Activities”, we had a decrease of $4,137 on investment in our oil and gas properties for the three months ended December 31, 2014 compared to the three months ended December 31, 2013. There were no significant investing activities during these periods.

As reported on our Consolidated Statement of Cash Flows under “Financing Activities”, for the three months ended December 31, 2014, we received $5,000 from one shareholder in exchange for 47,618 shares of our common stock upon the exercise by that shareholder of warrants at an exercise price of $0.105 per common share. As of December 31, 2014, we have no remaining outstanding loan payable.

Our cash and cash equivalents as of December 31, 2014 was $2,394,325 compared to $4,415,799 for the quarter ended December 31, 2013. This decrease of $2,021,474 in cash was primarily due to (i) $1,007,000 used to purchase and cancel a 2.5% interest out of the Purported 6.5% Royalty, as previously disclosed above; and (ii) 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 we entered into on July 31, 2013. 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. We also note that if we issue more shares of our common stock, our shareholders will experience dilution in the percentage of their ownership of common stock. We may not be able to raise sufficient funding from stock sales for long-term operations and if so, we may be forced to delay our business plans until adequate funding is obtained.

Off-Balance Sheet Arrangements

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, 2014, filed with the SEC on January 13, 2015. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those anticipated, believed, estimated or expected. Any forward looking statement speaks only as of the date on which it was made and, except as required by law, we disclaim any obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise. However, any further disclosures made on related subjects in subsequent reports on Forms 10-K, 10-Q, 8-K and any other SEC filing or amendments thereto should be consulted.

ITEM 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 December 31, 2014, an evaluation of the effectiveness of our “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our principal executive officer and principal financial officer. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that as of the end of that quarter, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes In Internal Control Over Financial Reporting

During the fiscal quarter ended December 31, 2014 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, 2014, filed with the SEC on January 13, 2015.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On October 3, 2014, we issued 47,618 shares of our Company stock upon exercise of warrants by a warrantholder, at an exercise price of $0.105 per share of common stock, for gross proceeds to our Company of $5,000. The shares of common stock were issued pursuant to Section 4(a) of the Securities Act.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Information to be Reported on Form 8-K

Deep Well reported all information that was required to be disclosed on Form 8-K during the period covered by this quarterly report on Form 10-Q.

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, 2014, 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.

ITEM 6. EXHIBITS

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.

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