UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

(Mark One)

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

 

For the quarterly period ended June 30, 2015

 

Or

 

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

 

For the transition period from ________to________

 

Commission file number 0-24012

 

DEEP WELL OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

 

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

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ 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 þ 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.

 

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

 

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

 

The number of shares of common stock outstanding as of June 30, 2015 was 229,374,605.

 

 

 

TABLE OF CONTENTS

 

		Page Number
PART I – FINANCIAL INFORMATION
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)	3
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	20
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	27
ITEM 4.	CONTROLS AND PROCEDURES	27
PART II – OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	27
ITEM 1A.	RISK FACTORS	27
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	27
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	27
ITEM 4.	MINE SAFETY DISCLOSURES	27
ITEM 5.	OTHER INFORMATION	28
ITEM 6.	EXHIBITS	28
SIGNATURES		29

 

  

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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

Condensed Consolidated Balance Sheets

June 30, 2015 and September 30, 2014

 

		June 30,				September 30,
		2015				2014
		(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	2,023,228			$	2,324,755
Accounts receivable net of allowance of $Nil (September 30, 2014 - $Nil)			226,765				1,050,099
Prepaid expenses			49,457				43,875
Total Current Assets			2,299,450				3,418,729
Long term investments			372,571				409,618
Oil and gas properties, net, based on successful efforts method of accounting			19,613,425				19,604,050
Property and equipment, net			217,697				259,198
TOTAL ASSETS		$	22,503,143			$	23,691,595
LIABILITIES
Current Liabilities
Accounts payable and accrued liabilities		$	182,794			$	714,198
Accounts payable and accrued liabilities– related parties			7,101				16,977
Total Current Liabilities			189,895				731,175
Asset retirement obligations (Note 10)			435,415				469,013
TOTAL LIABILITIES			625,310				1,200,188
SHAREHOLDERS’ EQUITY
Common Stock: (Note 11)
Authorized: 600,000,000 shares at $0.001 par value
Issued and outstanding: 229,374,605 shares
(September 30, 2014 – 229,326,987 shares)			229,374				229,326
Additional paid in capital			41,911,156				41,040,447
Accumulated Deficit			(20,262,697	)			(18,778,366	)
Total Shareholders’ Equity			21,877,833				22,491,407
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	22,503,143			$	23,691,595

  

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 and Nine Months Ended June 30, 2015 and 2014

 

		Three Months Ended				Three Months Ended				Nine Months Ended				Nine Months Ended
		June 30, 2015				June 30, 2014				June 30, 2015				June 30, 2014
Revenue		$	219,346			$	–			$	449,147			$	–
Royalty expenses			(11,127	)			–				(23,512	)			–
Revenue, net of royalty			208,219				–				425,635				–
Expenses
Operating expenses			425,684				–				1,540,206				–
Operating expenses covered by Farmout (Note 3)			(217,465	)			–				(1,114,571	)			–
General and administrative			337,016				55,031				1,434,203				862,245
Depreciation, accretion and depletion			21,721				25,790				64,541				74,315
Net loss from operations			(358,737	)			(80,821	)			(1,498,744	)			(936,560	)
Other income and expenses
Rental and other income			3,432				4,347				10,635				15,813
Interest income			1,081				2,091				3,778				9,009
Loss on disposal of assets			–				387				–				387
Net loss and comprehensive loss		$	(354,224	)		$	(73,996	)		$	(1,484,331	)		$	(911,351	)
Net loss per common share
Basic and Diluted		$	(0.00	)		$	(0.00	)		$	(0.00	)		$	(0.00	)
Weighted Average Outstanding Shares (in thousands)
Basic and Diluted			229,374				229,326				229,374				229,326

  

See accompanying notes to the condensed consolidated financial statements

 

 

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

(Unaudited)

Condensed Consolidated Statements of Cash Flows

For the Nine Months Ended June 30, 2015 and 2014

 

		June 30,				June 30,
		2015				2014
Operating Activities
Net loss		$	(1,484,331	)		$	(911,351	)
Items not affecting cash:
Share based compensation			865,756				239,480
Depreciation, accretion and depletion			64,541				74,315
Bad debts			–				428
Loss on disposal of assets			–				(387	)
Net changes in non-cash working capital (Note 13)			276,472				(593,796	)
Net Cash Used in Operating Activities			(277,562	)			(1,191,311	)
Investing Activities
Purchase of property and equipment			–				(408	)
Investment in oil and gas properties			(31,637	)			(3,635,922	)
Long term investments			2,671				(81,809	)
Net Cash Used in Investing Activities			(28,966	)			(3,718,139	)
Financing Activities
Payments on loan payable – related parties			–				(189,500	)
Proceeds from issuance of common stock			5,001				–
Net Cash Provided by (Used in) Financing Activities			5,001				(189,500	)
Decrease in cash and cash equivalents			(301,527	)			(5,098,950	)
Cash and cash equivalents, beginning of period			2,324,755				7,633,009
Cash and cash equivalents, end of period		$	2,023,228			$	2,534,059
Supplemental Cash Flow Information:
Cash paid for interest		$	–			$	–
Cash paid for income taxes		$	–			$	–

  

See accompanying notes to the condensed consolidated financial statements

 

 

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

(Unaudited)

Notes to the Condensed Consolidated Financial Statements

June 30, 2015

 

1.	NATURE OF BUSINESS AND BASIS OF PRESENTATION

 

Nature of Business

 

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

 

These 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.

 

2.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Consolidation

 

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

 

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 June 30, 2015 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 approximately $19.6 million and $19.6 million at June 30, 2015 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:

 

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

 

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

 

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 nine months ended June 30, 2015 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 June 30, 2015 and September 30, 2014, asset retirement obligations amount to $435,415 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 June 30, 2015 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 one 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 1,855,000 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

 

The Company has evaluated recent accounting pronouncements and their adoption has not had or is not expected 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.

 

3.	OIL AND GAS PROPERTIES

 

The Company’s oil sands acreage as of June 30, 2015, covers 43,015 gross acres (34,096 net acres) on 68 sections of land under nine oil sands leases. Until the Company extends the leases “into perpetuity” based on the Alberta governmental regulations, the lease expiration dates of the Company’s nine oil sands leases are as follows:

 

1)

32 sections of land under 5 oil sands leases are set to expire on July 10, 2018;

 

2)

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

 

3)

5 sections of land under 1 oil sands lease are set expire on April 9, 2024. It is the Company’s opinion that the Company has already met the governmental requirements for this lease and it will be applying to continue this lease into perpetuity.

 

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 June 30, 2015, the Company’s net payments due under this commitment are as follows:

 

			(Cdn $)
	2015		$	12,074
	2016		$	48,294
	2017		$	48,294
	2018		$	48,294
	2019		$	29,478
	Subsequent		$	22,400

 

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:

 

1)

drill 68 wells throughout the 68 sections; or

 

2)

drill 44 wells within the 68 sections and having acquired and processed two miles of seismic on each other undrilled section.

 

The Company plans to meet the second of these conditions. As at June 30, 2015 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 June 30, 2015 (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.

 

Farmout Agreement

 

On July 31, 2013, the Company entered into a Farmout agreement (the “Farmout Agreement”) with an additional joint venture partner (the “Farmee”) to fund the Company’s share of the Alberta Energy Regulator (“AER”) approved 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. As of June 30, 2015, the Farmee has not exercised this option.

 

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:

 

(i)

US $2,435,124 (Cdn $2,697,600) was paid to the JV Partner for the purchase and transfer of an undivided 3% interest out of the Purported 6.5% Royalty. The consideration paid was the original cost (in Canadian dollars) that the JV Partner paid to acquire its 3% interest in the Purported 6.5% Royalty.

 

(ii)

US $1,007,000 was paid to Mr. Malik Youyou, who is a director and majority shareholder of the Company, for the purchase and transfer of an undivided 2.5% interest out of the Purported 6.5% Royalty. The consideration paid was for the reimbursement of the original cost (in US dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5% Royalty from an arm’s length third party.

 

 

4.	CAPITALIZATION OF COSTS INCURRED IN OIL AND GAS ACTIVITIES

 

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 June 30, 2015, 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 nine months ended June 30, 2015 or in the fiscal year ended September 30, 2014.

 

The following table illustrates capitalized costs relating to oil producing activities as of June 30, 2015 and September 30, 2014:

 

			June 30, 2015				September 30, 2014
	Unproved Oil and Gas Properties		$	19,671,471			$	19,651,296
	Proved Oil and Gas Properties			4,568				4,568
	Accumulated Depreciation and Depletion			(62,614	)			(51,814	)
	Net Capitalized Cost		$	19,613,425			$	19,604,050

 

Depreciation and depletion expense for the nine months ended June 30, 2015 and 2014 was $10,800 and $7,178, respectively.

 

5.	EXPLORATION ACTIVITIES

 

The following table presents information regarding the Company’s costs incurred in the oil property acquisition, exploration and development activities for the nine months ended June 30, 2015 and 2014:

 

			June 30, 2015				June 30, 2014
	Acquisition of Properties:
	Proved		$	–			$	–
	Unproved			20,175				3,660,626
	Exploration costs			27,356				21,813
	Development costs			–				–

  

6.	INVESTMENT IN EQUITY SECURITIES

 

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

 

As of November 19, 2008, the Company 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, 2014, 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.

 

 

7.	PROPERTY AND EQUIPMENT

 

			June 30, 2015
							Accumulated				Net Book
			Cost				Depreciation				Value
	Computer equipment		$	32,197			$	31,723			$	474
	Office furniture and equipment			34,130				28,055				6,075
	Software			5,826				5,826				–
	Leasehold improvements			4,936				4,936				–
	Portable work camp			170,580				151,764				18,816
	Vehicles			38,077				33,861				4,216
	Oilfield equipment			249,046				152,133				96,913
	Road mats			364,614				324,245				40,369
	Wellhead			3,254				2,278				976
	Tanks			96,085				46,227				49,858
			$	998,745			$	781,048			$	217,697

 

			September 30, 2014
							Accumulated				Net Book
			Cost				Depreciation				Value
	Computer equipment		$	32,198			$	31,264			$	934
	Office furniture and equipment			34,130				26,880				7,250
	Software			5,826				5,826				–
	Leasehold improvements			4,936				4,936				–
	Portable work camp			170,580				146,211				24,369
	Vehicles			38,077				32,637				5,440
	Oilfield equipment			249,045				135,030				114,015
	Road mats			364,614				312,525				52,089
	Wellhead			3,254				2,053				1,201
	Tanks			96,085				42,185				53,900
			$	998,745			$	739,547			$	259,198

 

There was $41,501 of depreciation expense for the period ended June 30, 2015 (June 30, 2014 - $54,361).

 

8.	LONG TERM INVESTMENTS

 

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.

 

9.	SIGNIFICANT TRANSACTIONS WITH RELATED PARTIES

 

Accounts payable – related parties was $7,101 as of June 30, 2015 (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 June 30, 2015, 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 $112,590 to one related party, Concorde Consulting, an entity controlled by a director, for professional fees and consulting services provided to the Company during the period ended June 30, 2015 (June 30, 2014 - $124,997). These amounts were fully paid as of June 30, 2015.

 

 

10.	ASSET RETIREMENT OBLIGATIONS

 

The total future asset retirement obligation is estimated by management based on the Company’s net working interests in all wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At June 30, 2015, the Company estimates the undiscounted cash flows related to asset retirement obligation to total approximately $622,593 (September 30, 2014 - $ 689,445). The fair value of the liability at June 30, 2015 is estimated to be $435,415 (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:

 

			June 30, 2015				September 30, 2014
	Balance, beginning of period		$	469,013			$	446,155
	Liabilities incurred			–				73,395
	Effect of foreign exchange			(45,837	)			(64,079	)
	Disposal			–				(4,045	)
	Accretion expense			12,239				17,587
	Balance, end of period		$	435,415			$	469,013

 

11.	COMMON STOCK

 

As of June 30, 2015, the Company had outstanding approximately 229,374,605 shares of common stock.

 

Warrants

 

On June 23, 2014, 47,618 common share purchase warrants were 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 June 30, 2015:

 

			Shares Underlying Warrants Outstanding												Shares Underlying Warrants Exercisable
	Range of Exercise Price		Shares Underlying Warrants Outstanding				Weighted Average Remaining Contractual Life				Weighted Average Exercise Price				Shares Underlying Warrants Exercisable				Weighted Average Exercise Price
	$0.105 at June 30, 2015			71,857,141				0.40				0.105				71,857,141				0.105
	$0.075 at June 30, 2015			520,000				0.98				0.075				520,000				0.075
				72,377,141				0.40				0.105				72,377,141				0.105

 

The following is a summary of warrant activity for the period ended June 30, 2015:

 

			Number of Warrants				Weighted Average Exercise Price				Intrinsic Value
	Balance, September 30, 2014			72,424,759			$	0.105			$	0.215
	Cancelled			–				–				–
	Granted			–				–				–
	Exercised			47,618				0.105				–
	Balance, June 30, 2015			72,377,141			$	0.105			$	–
	Outstanding Warrants, June 30, 2015			72,377,141			$	0.105			$	–
	Exercisable Warrants, June 30, 2015			72,377,141			$	0.105			$	–

   

 

There were 72,377,141 warrants outstanding as of June 30, 2015 (September 30, 2014 – 72,424,759), which have a historical fair market value of $1,738,336 (September 30, 2014 - $1,738,336).

 

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%.

 

12.	STOCK OPTIONS

 

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.

 

Prior to October 1, 2013, the Company had a total of 4,350,000 options outstanding, that were previously granted to directors, consultants and an employee of the Company on March 23, 2011 and June 20, 2013, to purchase up to 3,450,000 and 900,000 shares, respectively, each of common stock at exercise prices ranging from $0.14 to $0.05, respectively, of which a total of 950,000 options granted on June 20, 2013 remain unvested.

 

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 June 30, 2015, the Company recorded share based compensation expense related to stock options in the amount of $865,756 (June 30, 2014 – $239,480) on the stock options that were previously granted. As of June 30, 2015, there was remaining unrecognized compensation cost of $491,074 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.

 

			Shares Underlying Options Outstanding												Shares Underlying Options Exercisable
	Range of Exercise Prices		Shares Underlying Options Outstanding				Weighted Average Remaining Contractual Life				Weighted Average Exercise Price				Shares Underlying Options Exercisable				Weighted Average Exercise Price
	$0.14 at June 30, 2015			900,000				0.73			$	0.14				900,000			$	0.14
	$0.05 at June 30, 2015			3,450,000				2.98				0.05				3,450,000				0.05
	$0.30 at June 30, 2015			250,000				3.33				0.30				250,000				0.30
	$0.34 at June 30, 2015			450,000				3.43				0.34				300,000				0.34
	$0.38 at June 30, 2015			6,780,000				4.22				0.38				2,660,000				0.38
	$0.23 at June 30, 2015			600,000				4.39				0.23				200,000				0.23
				12,430,000				3.59			$	0.26				7,760,000			$	0.20

 

The aggregate intrinsic value of exercisable options as of June 30, 2015, was $Nil (September 30, 2014 - $0.11).

 

The following is a summary of stock option activity as at June 30, 2015:

 

			Number of Underlying Shares				Weighted Average Exercise Price				Weighted Average Fair Market Value
	Balance, September 30, 2014			11,830,000			$	0.26			$	0.21
	Balance, June 30, 2015			12,430,000			$	0.26			$	0.21
	Exercisable, June 30, 2015			7,760,000			$	0.20			$	0.16

 

A summary of the options granted at June 30, 2015 and September 30, 2014 and changes during the periods then ended is presented below:

 

			June 30, 2015								September 30, 2014
			Shares				Weighted Average Exercise Price				Shares				Weighted Average Exercise Price
	Outstanding balance at beginning of period			11,830,000			$	0.26				900,000			$	0.14
												3,450,000				0.05
	Granted- October 28, 2013											250,000				0.30
	Granted- December 4, 2013											450,000				0.34
	Granted- September 19, 2014											6,780,000				0.38
	Granted- November 17, 2014			600,000				0.38
	Vested- November 17, 2014			200,000				0.38
	Vested- December 4, 2014			150,000				0.34
	Vested- June 20, 2015			950,000				0.05
	Outstanding at end of period			12,430,000			$	0.26				11,830,000			$	0.26
	Exercisable			7,760,000				0.20				6,460,000				0.21

 

There were 4,670,000 unvested stock options outstanding as of June 30, 2015 (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%.

 

13.	CHANGES IN NON-CASH WORKING CAPITAL

 

			Nine Months Ended				Nine Months Ended
			June 30, 2015				June 30, 2014
	Accounts receivable		$	823,334				(471,814	)
	Prepaid expenses			(5,582	)			123,548
	Accounts payable			(541,280	)			(245,530	)
			$	276,472				(593,796	)

 

14.	COMMITMENTS

 

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:

 

1)

Portwest Investments Ltd. (“Portwest”), a company owned 100% by Dr. Horst A. Schmid (the “Consultant”), for providing services to the Company as Chief Executive Officer and President for Cdn $12,500 per month. On July 1, 2005, the Company entered into a consulting agreement (the “Prior Agreement”) with Portwest, as filed with the Company’s annual report on Form 10-KSB filed on February 23, 2007, and incorporated by reference herein. On July 10, 2013, the Company and Portwest agreed to amend (the “Amending Agreement”) the Prior Agreement whereby the following was settled and amended:

	i.	Effective date of the Amending Agreement will be June 20, 2013;
	ii.	Term of Agreement will be until December 31, 2014;
	iii.	The fees payable to the Consultant in the Prior Agreement will be terminated and the Company will grant the Consultant 5-year options on 1,000,000 of its common shares exercisable at $0.05 per share, which was the market price at that time. One half of these shares were vested immediately and the remaining one half vested on June 20, 2014;
	iv.	The Consultant received:

                              

	a.	Cdn $70,000, and
	b.	850,000 units of the Company’s shares and warrants at a price of $0.05 per unit, which was the market price at the time. Each unit shall be comprised of one restricted Company common share and one 3 year full warrant entitling Portwest to be able to purchase another share for $0.075. The warrants expire on June 20, 2016.

 

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 June 30, 2015 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.

 

 

2)

Concorde Consulting, a company owned 100% by Mr. Curtis J. Sparrow, for providing services as Chief Financial Officer to the Company for Cdn $15,000 per month. As of June 30, 2015, the Company did not owe Concorde Consulting any of this amount.

 

Rental Agreement

 

See Note 17 subsequent events.

 

15.	LEGAL ACTIONS

 

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 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 seeking 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.

 

16.	CRUDE OIL AND NATURAL GAS PROPERTY INFORMATION

 

Results of Operations from Oil and Gas Producing Activities

 

The following table sets forth the results of the Company’s operations from oil producing activities from the Company’s Sawn Lake oil sands properties located in Alberta, Canada, for the periods ending June 30, 2015 and 2014 and for the year ended September 30, 2014:

 

			June 30, 2015				June 30, 2014				September 30, 2014
	Oil sales after royalties		$	425,635			$	–			$	47,116
	Production (Operating) expenses			(425,635	)			–				(47,115	)
	Exploration expenses			(27,356	)			–				(47,182	)
	Depreciation, accretion and depletion			(62,907	)			–				(97,646	)
	Oil sales less expenses			(90,263	)			–				(144,827	)
	Income tax expenses			–				–				–
	Results of operations from producing activities		$	(90,263	)		$	–			$	(144,827	)

 

For the periods ending June 30, 2015 and June 30, 2014, the Company booked oil revenue in the amount of $425,635 and $Nil, respectively, after deduction of royalties. For the periods ending June 30, 2015 and June 30, 2014, the volumes of oil delivered were booked to be 17,043 and Nil barrels, respectively, net to the Company, before royalties, with an average oil sales price of $26.35 per barrel for the period ending June 30, 2015. 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 $22.8 million to the operator of the SAGD Project for the Farmee’s share and the Company’s share of the capital costs and start-up operating expenses of the SAGD Project up to June 30, 2015. These costs include the capital costs of 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 with pipelines to the steam plant facility along with a fuel source tie-in pipeline; emulsion treatment package; Phase 2 front end costs; and the start-up operating expenses associated with the steaming and production of the SAGD well pair up to June 30, 2015.

 

 

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 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 capital 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.

 

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, and pipelines to connect the source wells and fuel tie-in to the SAGD facility. This first phase included start-up steam operations of the SAGD facility with production commencing on September 16, 2014. The estimated capital costs to complete the SAGD Project steam plant facility with one SAGD well pair has been estimated by the operator to be Cdn $32.8 million on a 100% working interest basis, of which the Company’s share is covered under the Farmout Agreement (this estimate does not include start-up operating expenses to produce bitumen from the first SAGD well pair).

 

SAGD Project Phase 2 - The Phase 2 front end work includes 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.

 

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 capital costs and operating expenses paid by the Farmee to the operator of the SAGD Project. See Note 4 herein “Capitalization of Costs Incurred in Oil and Gas Activities”.

 

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

 

See Note 5 herein “Exploration Activities”.

 

17.	Subsequent events

 

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 in Cdn dollars are as follows:

 

	2015 Q4 (July - September)			7,969
	2016 Q1 (October - December)			7,969
	2016 Q2 (January - March)			7,969
	2016 Q3 (April - June)			7,969
	2016 Q4 (July - September)			7,969
	2017 Q1 (October - December)			7,969
	2017 Q2 (January - March)			7,969
	2017 Q3 (April - June)			7,969

 

On July 28, 2015, the Company’s Board approved the extension of the expiration date of some warrants to purchase shares of the Company’s common stock. The exercise price of the warrants remained unchanged at $0.105 per share. As a result of this extension, the expiration dates of the warrants were amended from the original expiry date of November 23, 2015 to November 23, 2016, with all other terms of the original warrants remaining in full force and effect. In consideration of extending the expiry date of this series of warrants, the number of outstanding warrants was reduced from 71,857,141 to 52,155,221 common share purchase warrants.

 

 

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 quarterly report on Form 10-Q to “$” are to United States dollars and references to “Cdn$” are to Canadian dollars. On August 11, 2015, the noon rate of exchange for Canadian dollars expressed in US$ was Cdn$1.00 = US$0.7606 as reported by the Bank of Canada. The following table sets forth the rates of exchange for the Cdn$, expressed in US dollars, in effect at the end of the following period and the average noon rate of exchange during such period, based on the noon rates of exchange for such periods as reported by the Bank of Canada.

 

Period Ending June 30		2015				2014
Rate at end of the period			0.8017				0.9367
Average rate for the three month period			0.8132				0.9170

 

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 where we have working interests ranging from 25 % to 100% 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 Venture Marketplace under the symbol DWOG. The OTCQB Venture Marketplace requires companies to be fully compliant in their filing requirements under the U.S. Securities and Exchange Act and must meet eligibility standards to trade on OTCQB, which include, but are not limited to, the submission of an annual verification and management certification confirming that the listed company is current in its reporting requirements. 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. In July 2013, we entered into a Steam Assisted Gravity Drainage Demonstration project (“SAGD Project”) to jointly participate in an Alberta Energy Regulator (“AER”) approved SAGD Project, where we have a 25% working interest, which began producing oil on September 16, 2014. The following table sets forth certain financial information:

 

		Three Months Ended				Three Months Ended				Nine Months Ended				Nine Months Ended
		June 30, 2015				June 30, 2014				June 30, 2015				June 30, 2014
Revenue		$	219,346			$	–			$	449,147			$	–
Provincial Royalty expenses			(11,127	)			–				(23,512	)			–
Revenue, net of royalty			208,219				–				425,635				–
Expenses
Operating expenses			425,684				–				1,540,206				–
Operating expenses covered by Farmout (Note 3)			(217,465	)			–				(1,114,571	)			–
General and administrative			61,297				14,251				568,447				622,765
Share based compensation			275,719				40,780				865,756				239,480
Depreciation, accretion and depletion			21,721				25,790				64,541				74,315
Net loss from operations			(358,737	)			(80,821	)			(1,498,744	)			(936,560	)
Other income and expenses
Rental and other income			3,432				4,347				10,635				15,813
Interest income			1,081				2,091				3,778				9,009
Loss on disposal of assets			–				387				–				387
Net loss and comprehensive loss		$	(354,224	)		$	(73,996	)		$	(1,484,331	)		$	(911,351	)

 

 

 

 

Oil sales terminal at our joint SAGD Project

 

First production of oil in the form of bitumen began on September 16, 2014. For the three month period ending June 30, 2015, we booked oil revenue in the amount of $219,346 before deduction of royalties. For the three month period ending June 30, 2015, the volumes of oil delivered were booked to be 6,892 barrels net to our Company, before royalties, with an average oil sales price of $31.83 per barrel (Cdn$39.14 per barrel). For the nine month period ending June 30, 2015, we booked oil revenue in the amount of $449,147 before deduction of royalties. For the nine month period ending June 30, 2015, the volumes of oil delivered were booked to be 17,043 barrels net to our Company, before royalties, with an average oil sales price of $26.35 per barrel (Cdn$31.60 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, but paid in Canadian dollars. While oil prices have remained low, the Canadian dollar has weakened and offset much of this 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 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 (as defined below) has since paid Cdn$22.8 million to the operator of the SAGD Project for the Farmee’s share and our share of the capital costs and start-up operating expenses of the SAGD Project up to June 30, 2015. 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 with pipelines to the steam plant facility along with a fuel source tie-in pipeline; emulsion treatment package; Phase 2 front end costs; and the start-up operating expenses associated with the steaming and production of the SAGD well pair up to June 30, 2015.

 

For the three months ended June 30, 2015, our general and administrative expenses increased by $281,985 compared to the three months ended June 30, 2014, which was primarily due to (i) an increase of $234,939 in non-cash share based compensation charged to expense, which was mainly due to vested stock options we granted in 2014 to our directors and contractors; and (ii) an increase of foreign exchange loss of $51,253. 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 $179,743 for the three months ended June 30, 2015 compared to $184,231 for the three months ended June 30, 2014.

 

For the nine months ended June 30, 2015, our general and administrative expenses increased by $571,958 compared to the nine months ended June 30, 2014, which was primarily due to (i) an increase of $626,276 in non-cash share based compensation charged to expense, which was mainly due to vested stock options we granted in 2014 to our directors and contractors as described above; (ii) an increase of foreign exchange loss of $49,600; and (iii) an increase in engineering fees of $25,267. These increases in our general and administrative expenses were offset by (i) a decrease in legal fees of $64,174; and (ii) a decrease of general office expenses. We also received $270,000 during the last nine months from one of our joint venture partners in accordance with the 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 $671,760 for the nine months ended June 30, 2015 compared to $774,366 for the nine months ended June 30, 2014.

 

For the three months ended June 30, 2015, our depreciation, depletion, and accretion expense decreased by $4,069 compared to the three months ended June 30, 2014, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition. No significant asset purchases were made in the quarter ended June 30, 2015.

 

For the nine months ended June 30, 2015, our depreciation and accretion expense decreased by $9,774 compared to the nine months ended June 30, 2014, which was primarily due to the depreciating value of our assets. Depreciation expense is computed using the declining balance method over the estimated useful life of the asset. In compliance with our accounting policy, only half of the depreciation is taken in the year of acquisition. No significant depreciable asset purchases were made in the quarter ended June 30, 2015.

 

For the three months ended June 30, 2015, there were no significant increases or decreases for rental and other income compared to the three months ended June 30, 2014.

 

For the nine months ended June 30, 2015, rental and other income decreased by $5,178 compared to the nine months ended June 30, 2014.

 

 

For the three months ended June 30, 2015, interest income decreased by $1,010 compared to the three months ended June 30, 2014.

 

For the nine months ended June 30, 2015, interest income decreased by $5,231 compared to the nine months ended June 30, 2014.

 

As a result of the above transactions, we recorded an increase of $280,228 in our net loss and comprehensive loss from operations for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. As discussed above, this increase was primarily due to an increase in non-cash share based compensation expenses and foreign exchange losses.

 

As a result of the above transactions, we recorded an increase of $572,980 in our net loss and comprehensive loss from operations for the nine months ended June 30, 2015 compared to the nine months ended June 30, 2014. As discussed above, this increase was primarily due to an increase in non-cash share based compensation expenses and foreign exchange losses.

 

Operations

 

As previously disclosed, we entered into the Farmout Agreement with our new joint venture partner (the “Farmee”), to fund our share of the SAGD Project. The SAGD Project is located on our Sawn Lake properties in the Peace River oil sands region of Alberta. In accordance with the Farmout Agreement, the Farmee has agreed to provide up to $40,000,000 for the funding of our portion of the costs for the SAGD Project, in return for a net 25% working interest in 12 sections where we had a working interest of 50% before the execution of the Farmout Agreement. Also, the Farmee is required to provide funding to cover our monthly operating expenses not to exceed $30,000 per month. In addition, as amended on November 17, 2014, the Farmee has the option to elect, prior to December 31, 2015, to obtain additional working interests ranging from 45% to 50% in the remaining 56 sections of land where we have working interests ranging from 90% to 100%, by committing an additional $110,000,000 of financing for the development of our Sawn Lake oil sands properties.

 

The first oil production from our joint 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 start of our bitumen sales averaged 221 barrels per day, half way through the 3rd thirty day period since the start-up of production in September of 2014. Production from our joint SAGD Project has since increased significantly. For the month of June 2015, bitumen sales averaged 385 barrels per day, with a Steam Oil Ratio (“SOR”) of 4.54. A single daily production peak was achieved in June of 2015 at 443 barrels per day. All of these production numbers are on a 100% basis with our Company owning a 25% working interest. Production from the SAGD Project is continuing to slowly ramp up and the steam chamber has not yet reached the top of the Bluesky reservoir. Bitumen production on a 100% basis averaged 399 barrels per day (100 barrels per day net to us) in July 2015 with a SOR of 4.4. Based on the operator's forecasts, the steam chamber is expected to reach the top of the Bluesky reservoir by the end of September 2015 and maximum oil production is now expected to be reached by the end of November of 2015.

 

 

 

 

  

 

 

The objective of this initial SAGD well pair was to establish that this thermal technology is effective in producing oil from the Bluesky reservoir formation and to provide valuable productivity information about the reservoir. Results to date indicate that the use of SAGD technology is successful in producing oil in the form of bitumen from the Bluesky reservoir. Based on 100% working interest (we have 25%), for the months of January, February and March of 2015, monthly gross oil sales averaged 252, 294 and 319 barrels of oil per day, respectively. In April the operator had to shut down production operations of the SAGD well pair to repair the electrical submersible pump, and as a result of this temporary shut-in the SAGD well pair only produced for two weeks in the month averaging 125 barrels of oil per day for the month of April (on a 100% basis). Production for the SAGD well pair resumed on May 1, 2015. Based on 100% working interest (we have 25%), for the months of May and June of 2015, monthly gross oil sales averaged 381 and 385 barrels of oil per day, respectively. These early stage production numbers along with the corresponding steam oil ratios compare favorably to analogous reservoirs in thermal recovery projects operated by other companies of similar reservoir types that we (and the operator of our joint SAGD Project) are monitoring and using as a basis of comparison. The capital costs to complete the SAGD Project steam plant facility with one SAGD well will have been Cdn$36 million on a 100% working interest basis for Phase 1 and the front end costs of Phase 2 (this estimate does not include operating expenses to produce bitumen from the SAGD well pair), of which our share is covered under the Farmout Agreement.

 

The drilling of an additional SAGD well pair and the associated expansion of the current SAGD plant facility has been deferred due to the decline in oil prices. However, the operator of the SAGD Project has proceeded with the permitting and approvals for additional well pairs in addition to the Phase 2 front-end work (purchasing of long lead items such as pipe), 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 Alberta Oil Ltd. (“Northern”), we acquired from one of our joint venture partners (“JV Partner”) and one related party (Mr. Malik Youyou), and subsequently cancelled, 5.5% of a disputed 6.5% overriding royalty claim (the “Purported 6.5% Royalty”) on some 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:

 

(i)

$2,435,124 to our JV Partner for the purchase and transfer of an undivided 3% interest out of the Purported 6.5% Royalty. The consideration paid was the original cost (in Canadian dollars) that our JV Partner paid to acquire its 3% interest in the Purported 6.5% Royalty.

 

(ii)

$1,007,000 to Mr. Malik Youyou, who is a director and majority shareholder of our Company, for the purchase and transfer of an undivided 2.5% interest out of the Purported 6.5% Royalty. The consideration paid was for the reimbursement of the original cost (in US dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5% Royalty from an arm’s length third party.

 

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 what we could 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. Now that preliminary and several months of production testing data from our joint SAGD project is available to us, we intend to use that information to start on the front end engineering of our HCSS Project where we plan to drill two horizontal wells to test the use of HCSS technology. As we continue to receive further production performance data from the operator we intend to further refine our HCSS Project development plan. We are currently in the process of scouting out and surveying our plans for our proposed thermal project site on the north half of section 10-92-13W5, along with preforming an environmental field assessment report for our project site location to acquire the mineral surface license for the proposed drilling of two horizontal wells.

 

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.

  

 

Liquidity and Capital Resources

 

As of June 30, 2015, our total assets were $22,503,143 compared to $23,691,595 as of September 30, 2014. This decrease of $1,188,452 in our total assets was primarily due to a decrease in our accounts receivable, as a result of a subsequent reimbursement of Cdn$1,200,000 from the Farmee in October 2014 for the SAGD Project winterization program.

 

Our total liabilities as of June 30, 2015 were $625,310 compared to $1,200,188 as of September 30, 2014. This decrease of $574,878 in our total liabilities was primarily the result of our payment for outstanding accounts payable to the operator of the SAGD Project for operating expenses, which was subsequently paid by the Farmee to us just before our 2014 year end, under the Farmout Agreement.

 

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

 

		Nine Months Ended				Year Ended
		June 30, 2015				September 30, 2014
Current Assets		$	2,299,450			$	3,418,729
Current Liabilities			189,895				731,175
Working Capital		$	2,109,555			$	2,687,554

 

As of June 30, 2015, we had working capital of $2,109,555 compared to a working capital of $2,687,554 as of September 30, 2014. This decrease is mainly the result of (i) the net change of accounts receivable, offset by the decrease of accounts payable as described above; and (ii) cash used for general and administrative expenses. As of June 30, 2015, we had no long-term third party debt other than our estimated asset retirement obligations on oil and gas properties.

 

On July 31, 2013, we entered into the Farmout Agreement to fund our share of the costs of our joint SAGD Project. As of June 30, 2015, we recorded $176,358 in accounts payable due to the operator for our working interest share of the outstanding monthly operating expenses of the SAGD Project, of which all is reimbursable by the Farmee in accordance with the Farmout Agreement. Therefore, this amount is also recorded in accounts receivable to be paid to us from the Farmee to cover our share of the costs of the SAGD Project.

 

As reported on our Consolidated Statement of Cash Flows under “Operating Activities”, for the nine months ended June 30, 2015, our net cash used in operating activities was $277,562 compared to $1,191,311 for the nine months ended June 30, 2014. This decrease of $913,749 was primarily the result of non-cash working capital related to accounts receivable and accounts payable as disclosed above.

 

As reported on our Consolidated Statement of Cash Flows under “Investing Activities”, we had a decrease of $3,689,173 in the investment in our oil and gas properties for the nine months ended June 30, 2015, compared to the nine months ended June 30, 2014. This decrease is due to two Royalty purchases: (i) On March 18, 2014, $2,435,124 (Cdn$2,697,600) was paid to a JV Partner for the purchase and transfer of an undivided 3% interest out of the Purported 6.5% Royalty. The consideration paid was the original cost (in Canadian dollars) that the JV Partner paid to acquire its 3% interest in the Purported 6.5% Royalty; and (ii) On June 27, 2014, $1,007,000 was paid to Mr. Malik Youyou, who is a director and majority shareholder of our Company, for the purchase and transfer of an undivided 2.5% interest out of the Purported 6.5% Royalty. The consideration paid was for the reimbursement of the original cost (in US dollars) that Mr. Youyou paid to acquire this 2.5% interest in the Purported 6.5% Royalty from an arm’s length third party.

 

As reported on our Consolidated Statement of Cash Flows under “Financing Activities”, for the nine months ended June 30, 2015, 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.

 

Our cash and cash equivalents as of June 30, 2015 was $2,023,228 compared to $2,534,059 as of June 30, 2014. This decrease of $510,831 in cash was primarily due to general and administrative expenses. As of June 30, 2015, we had no long-term debt other than our estimated asset retirement obligations on oil and gas properties.

 

Our current SAGD Project operating costs are covered by the Farmout Agreement. For our long-term operations, we anticipate that, among other alternatives, we may raise funds during the next twenty-four months through sales of our equity securities. 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:

 

●

our current business strategy;

●

our future financial position and projected costs;

●

our projected sources and uses of cash;

●

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

●

our drilling and testing plans;

●

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

●

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

●

our reserves and resources estimates;

●

the timing and sources of our future funding.

●

the quantity and value of our reserves;

●

the intent to issue a distribution to our shareholders;

●

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

●

our plans for development of our Sawn Lake properties;

●

production levels from our current SAGD Project;

●

costs of our current SAGD Project;

●

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

●

additional sources of funding from the Farmout Agreement;

●

funding from the Farmee to cover our monthly operating expenses;

●

our access and availability to third-party infrastructure;

●

present and future production of our properties; and

●

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

 

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

 

●

changes in general business or economic conditions;

●

changes in legislation or regulation that affect our business;

●

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

●

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

●

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

●

future marketing and transportation of our produced bitumen;

●

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

●

our Farmout Agreement and joint operating agreements;

●

opposition to our regulatory requests by various third parties;

●

actions of aboriginals, environmental activists and other industrial disturbances;

●

the costs of environmental reclamation of our lands;

●

availability of labor or materials or increases in their costs;

●

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

●

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

●

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

●

volatility in market prices for oil, bitumen, natural gas, diluent and natural gas liquids;

 

 

●

competition;

●

changes in labor, equipment and capital costs;

●

future acquisitions or strategic partnerships;

●

the risks and costs inherent in litigation;

●

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

●

product supply and demand;

●

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

●

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

●

the ability to meet minimum level of requirements to continue our oil sands leases beyond their expiry dates;

●

changes in general business or economic conditions;

●

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

●

geological, technical, drilling and processing problems;

●

third party performance of obligations under contractual arrangements;

●

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

●

treatment under governmental regulatory regimes and tax laws;

●

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

●

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

●

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

●

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

●

fluctuations in currency and interest rates; and

●

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

 

The preceding bullets outline some of the risks and uncertainties that may affect our forward-looking statements. For a full description of risks and uncertainties, see the sections entitled “Risk Factors” and “Environmental Laws and Regulations” of our annual report on Form 10-K for the fiscal year ended September 30, 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 June 30, 2015, an evaluation of the effectiveness of our “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our principal executive officer and principal financial officer. Based upon that evaluation, our principal executive officer and principal financial officer have concluded that as of the end of that quarter, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

 

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

 

Changes In Internal Control Over Financial Reporting

 

During the fiscal quarter ended June 30, 2015 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

 

None.

 

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

 

None.

 

ITEM 4.

MINE SAFETY DISCLOSURES

 

Not applicable.

 

 

ITEM 5.

OTHER INFORMATION

 

Information to be Reported on Form 8-K

 

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

 

On July 28, 2015, we and certain holders of warrants to acquire shares of common stock approved the amendment of the warrants held by those warrant holders. In consideration for extending the expiration date of the applicable warrants from November 23, 2015 to November 23, 2016, the aggregate number of shares of our common stock issuable upon exercise of the warrants was reduced from 71,857,141 to 52,155,221. Given the present oil and stock market condition, the warrants holders informed our Company of their unwillingness to exercise their warrants on or before the original expiration date. Therefore, we agreed to extend the term of the warrants but only for a reduced number of warrants at the same exercise price. This reduced number was determined by estimating a value similar of the new extended warrants to the original, now forfeited warrants, with the same strike price, at the time our management and the warrants holders agreed to the basic terms. These terms were subsequently discussed by our Company’s Corporate Governance and Nominating Committee (our “Committee”), which recommended to our Board to accept the new terms as set out between management and the warrants holders. Our Board subsequently agreed with our Committee’s recommendation. No other amendments were made to the terms of the applicable warrants. The amended warrants are filed herewith as exhibits 4.1, 4.2 and 4.3

 

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

 

Exhibit No.		Description
4.1		Warrant #31 Amending Agreement dated July 28, 2015, filed herewith.
4.2		Warrant #32 Amending Agreement dated July 28, 2015, filed herewith.
4.3		Warrant #35 Amending Agreement dated July 28, 2015, filed herewith.
31.1		Certification of President and Chief Executive Officer pursuant to Rule 13a-14(a).
31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a).
32.1		Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
101		Interactive Data Files

 

 

SIGNATURES

 

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

 

	DEEP WELL OIL & GAS, INC.
	By	/s/ Horst A. Schmid
		Dr. Horst A. Schmid
		Chief Executive Officer and President
		(Principal Executive Officer)
	Date	August 14, 2015
	By	/s/ Curtis Sparrow
		Mr. Curtis James Sparrow
		Chief Financial Officer
		(Principal Financial and Accounting Officer)
	Date	August 14, 2015

  

 

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