| Summary Of Significant Accounting Policies |
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Description of Operations. Samson Oil & Gas Limited along with its consolidated subsidiaries (“Samson” or the “Company”), is engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties with a focus on properties in North Dakota and Montana.
Going concern. These financial statements have been prepared on the going concern basis, which contemplates the continuity of normal business activities and the realisation of assets and settlement of liabilities in the normal course of business.
We incurred a net loss of $2 .3 million and had net cash outflows from ope rating activities of $2.6 million for the year ended June 30, 2017. As at that date, the Consolidated Entity’s total current liabilities of $ 28.7 million exceed its total current assets of $ 2.7 million . Our ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and raising further capital. These factors raise substantial doubt over our ability to continue as a going concern and therefore whether we will reali z e our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the financial report.
To address these concerns we have undertaken the following plan :
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As at the reporting date we are in breach of our covenants with the Mutual of Omaha Bank (the “Bank”), resulting in borrowings payable of $23 .5 million being classified as current liabilities (Note 9 ). We are currently negotiating with Mutual of Omaha Bank in an effort to obtain a waiver for the breach. As at the date of this report, no waiver has been received;
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We have recently engaged a financial advisor in connection with the proposed private placement of up to USD$40 million, or such other amount as may be agreed in writing between the parties, of debt or equity linked debt securities. This reflects our plan to re-pay borrowings to Mutual of Omaha Bank in addition to providing working capital in accordance with management’s plan to drill the proved undeveloped well locations in the Forman Butte Project . This proposed financing may also include placement of equity securities of the Company , including preferred shares; and
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We are also currently negotiating with a number of parties with respect to the potential sale of between 25% and 50% of our working interest in our oil and gas properties. This sale would again provide us with the necessary working capital to carry out our drilling program. portion of revenue generated from such activities would be used to fund the repayment of our borrowings.
While management believe that we will have the ability to refinance our credit facility and issue debt or equity securities there can be no assurances that our efforts will be successful. In addition, given our current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available.
The financial report does not include any adjustments relating to the amounts or classification of recorded assets or liabilities that might be necessary if the Company does not continue as a going concern.
Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP).
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long–lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) certain accrued liabilities; (9) valuation of share-based payments, (10) income taxes and (11) carrying value of exploration and evaluation expenditure. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions through the date of this report for matters that may require recognition or disclosure in these financial statements.
Business Segment Information. The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers.
Revenue Recognition and Gas Imbalances. Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of completed deliveries where title has transferred. Title to oil sold is typically transferred at the wellhead.
The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at June 30, 2017 or 2016.
Cash and Cash Equivalents. The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank .
Accounts Receivable. The components of accounts receivable include the following:
June 30
2017
2016
Oil and natural gas sales
$ 894,523
$ 1,717,110
Cost recovery from drilling partners
572,082
275,018
Other
83,833
4,287
Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2017 and 2016
$ 1,550,438
$ 1,996,415
The Company's accounts receivable result from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are primarily from the operators of our various projects, who negotiate the sale of oil and gas to third parties on our behalf.
Accruals. The components of accrued liabilities for the years ended June 30, 2017 and 2016 are as follows:
2017
2016
Other accruals
821,319
629,975
Deposit received for asset sale
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1,000,000
$ 821,319
$ 1,629,975
Other accruals includes an estimate of the costs expected to be incurred with respect to the asset retirement obligation in the next twelve months.
The deposit received from the asset sale in 2016 was transferred to income from sale of assets following the closing of the transaction in October 2016.
Oil and Gas Properties.
Oil and gas properties and equipment consist of the following at June 30:
2017
2016
Proved properties
$ 43,852,023
$ 45,177,047
Lease and well equipment
2,119,641
1,394,291
Less accumulated depreciation, depletion and impairment
(14,474,391)
(15,049,015)
$ 31,497,273
$ 31,522,323
Assets held for sale
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13,768,865
Unproved acreage
$ 271,078
$ 220,703
Capitalized exploration expense
$
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$ 0
The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly.
Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method. Mineral interests and leasehold acquisition costs are depleted over total proved reserves while cost of completed wells and related facilities and equipment are depleted over proved developed producing reserves.
If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis.
As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field.
The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment.
Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Company. Impairment on properties sold is recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term .
Assets held for sale
On June 30, 2016, the Company signed a Purchase and Sale Agreement for the sale of its interests in the North Stockyard field. The purchase price of the acquisition was $15 million and the acquisition closed on October 31, 2016. The effective date of the acquisition is the day after the closing date. The Company received a $1 million deposit from the purchaser on the date of signing, which was recorded in current liabilities at June 30, 2016 .
Exploration and evaluation costs including capitalized exploration written off and dry hole expenses
Exploration and evaluation assets are assessed for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. When assessing for impairment consideration is given to but not limited to the following:
the period for which Samson has the right to explore;
planned and budgeted future exploration expenditure;
activities incurred during the year; and
activities planned for future periods.
If, after having capitalized expenditure under our policy, the Company concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement.
During the fiscal year ended June 30, 2016, we expensed $4.2 million in deferred exploration expense in relation to our Hawk Springs project area.
Impairment
The Company recorded impairment charges of $0.2 million and $11.0 million for the years ended June 30, 2017 and 2016 respectively.
The charges in the fiscal year ended June 30, 2017 related to the write down of the value in our oil inventory to lower of cost or net realizable value.
The charges in the fiscal year ended June 30, 2016 related to the impact of the drop in the oil price on our North Stockyard, Rainbow and State GC project areas.
Other Property and Equipment.
Other property and equipment, which includes leasehold improvements, office and other equipment, are stated at cost. Depreciation and amortization are calculated using the straight–line method over the estimated useful lives of the related assets, ranging from 3 to 25 years.
Depreciation and amortization expense for the years ended June 30, 2017 and 2016 was $0.1 million and $0.1 million, respectively.
Other property and equipment consists of the following at June 30:
2017
2016
Furniture, fittings and equipment
$ 990,022
$ 882,469
Less accumulated depreciation
(693,945)
(573,995)
$ 296,077
$ 308,474
Derivative Financial Instruments. The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. All of the Company's derivative counterparties are major oil companies. The Company has elected not to apply hedge accounting to any of its derivative transactions and consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges.
Asset Retirement Obligations. The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long–lived asset are recorded at the time the well is spud or acquired.
Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non–capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company is not aware of any material noncompliance with existing laws and regulations.
Income Taxes. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50 % likelihood of being realized upon ultimate settlement.
Earnings per Share. Basic earnings (loss) per share are calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding since the impact would be anti-dilutive. When the Company records a net loss, none of the loss is allocated to the unexercised stock options since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, outstanding options will have no dilutive impact to the Company’s basic earnings per share.
The following potential common shares relating to options and warrants have been excluded from the calculation of diluted earnings per share as the related impact was anti-dilutive.
Year ended June 30,
2017
2016
Dilutive
-
-
Anti–dilutive
287,956,323
321,955,194
Stock-Based Compensation. Stock-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). The Company recognizes stock-based compensation net of an estimated forfeiture rate, and recognizes compensation expense only for shares that are expected to vest. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered.
Foreign Currency Translation. The functional currency of Samson Oil & Gas Limited (Parent Entity) is Australian dollars, the reason for this being the majority of cash flows of the Parent Entity are denominated in Australian dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S . dollars. The presentation currency of the Consolidated Entity is U.S. dollars.
Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss
Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income.
Business Combinations Samson applies the acquisition method in accounting for business combinations. The consideration transferred by the Company is calculated as the sum of the acquisition date fair value of assets transferred, liabilities incurred and any equity interests issued by the Company, which includes the fair value of any asset or liability arising from any contingent consideration arrangements. Acquisition costs are expensed as incurred. The Company treats the acquisition of oil and gas assets as a business combination.
The Company recognizes identifiable assets acquired and liabilities assumed in a business combination regardless of whether they have been previously recognized in the acquiree’s financial statements prior to the acquisition. Assets acquired and liabilities assumed are generally measured at their acquisition date fair values.
If the fair values of identifiable net assets exceeds the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately.
In the prior period, the Company recognized a gain on bargain purchase of $10.7 million with respect to its acquisition of certain producing and non producing assets, known as the Foreman Butte project.
Impact of Recently Adopted Accounting Standards.
There have been no recently adopted accounting standards that would impact our business.
Recently Issued Accounting Pronouncements
In August 2014, the FASB issued new guidance related to the disclosures around going concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. This standard has been adopted and the Company has added the appropriate disclosures.
In November 2014, the FASB issued ASU No. 2014-16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity. This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted. The Compan y has adopted this standard and it did not have a material impact on its consolidated financial statements.
ASU 2016-02, Leases (Topic 842) This ASU, among other provisions, requires lessees to recognize right of use assets and leases liabilities for all leases not considered short term leases. The ASU is effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years This standard is not expected to have a significant impact on the Company as it does not currently engage in significant leasing activity.
ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Update (ASU) 2014-09 provides a new framework for addressing revenue recognition issues and upon its effective date, replaces almost all existing revenue recognition guidance. While the revenue recognition policies of all entities will be impacted by this standard, we do not expect the impact to be significant. For public business entities, the guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.
We have not yet begun to assess the impact on our financial reporting of the standards disclosed above that have not yet taken effect. However, we do not expect these changes to have a significant impact on our financial statements with the exception of additional disclosures.
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