Document And Entity Information
Document And Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Jun. 30, 2019 | Oct. 15, 2019 | Dec. 31, 2018 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Jun. 30, 2019 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Samson Oil & Gas LTD | ||
Entity Central Index Key | 0001404079 | ||
Current Fiscal Year End Date | --06-30 | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Common Stock, Shares Outstanding | 328,300,044 | ||
Entity Public Float | $ 2.1 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 685,737 | $ 1,376,676 |
Restricted cash - required reserve amounts related to Credit Agreement | 2,088,750 | |
Accounts receivable, net of allowance for doubtful accounts of $250,000 and $75,000, respectively | 1,982,123 | 1,908,879 |
Oil Inventory | 219,288 | |
Prepayments | 137,342 | |
Total current assets | 4,756,610 | 3,642,185 |
PROPERTY, PLANT AND EQUIPMENT | ||
Oil and gas properties, net, successful efforts method of accounting, less accumulated depreciation, depletion and amortization of $9,491,784 and $6,105,315 at June 30, 2019, and 2018, respectively | 30,214,829 | 30,420,841 |
Other property and equipment, net of accumulated depreciation and amortization of $755,241 and $775,057 at June 30, 2019 and June 30, 2018, respectively | 174,931 | 242,822 |
Net property, plant and equipment | 30,389,760 | 30,663,663 |
OTHER ASSETS | ||
Fair value of derivative instruments | 365,542 | |
Deposits | 559,722 | 584,644 |
Deferred tax asset | 780,000 | 732,056 |
TOTAL ASSETS | 36,851,634 | 35,622,548 |
CURRENT LIABILITIES | ||
Accounts payable | 8,121,217 | 8,532,987 |
Accrued liabilities | 1,300,185 | 1,339,164 |
Fair value of derivative instruments | 150,703 | 1,210,795 |
Current portion of asset retirement obligation | 274,404 | |
Current portion of credit facility | 33,500,000 | 23,867,558 |
Total current liabilities | 43,346,509 | 34,950,504 |
Asset retirement obligations | 3,336,376 | 3,344,112 |
Total liabilities | 46,682,885 | 38,294,616 |
Commitments and contingencies (Note 11 & 12) | ||
STOCKHOLDERS' EQUITY (DEFICIT) | ||
Common stock, 328,300,044 shares issued and outstanding at June 30, 2019 and 2018 | 106,743,167 | 106,743,167 |
Accumulated other comprehensive income | 835,404 | 846,556 |
Accumulated deficit | (117,409,822) | (110,261,791) |
Total stockholders' deficit | (9,831,251) | (2,672,068) |
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT | $ 36,851,634 | $ 35,622,548 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Consolidated Balance Sheets [Abstract] | ||
Accounts receivable, allowance for doubtful accounts | $ 250,000 | $ 75,000 |
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion Amortization and Impairment | 9,491,784 | 6,105,315 |
Other property and equipment, accumulated depreciation and amortization | $ 755,241 | $ 775,057 |
Common stock, shares issued | 328,300,044 | 328,300,044 |
Common stock, shares outstanding | 328,300,044 | 328,300,044 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations And Comprehensive Loss - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
OPERATING REVENUES: | ||
Total oil and gas income | $ 12,662,865 | $ 10,058,719 |
OPERATING EXPENSES: | ||
Lease operating expense | 12,341,869 | 6,866,922 |
Depletion, depreciation, amortization and accretion of asset retirement obligation | 2,385,964 | 1,488,772 |
Exploration and evaluation expenditure | 73,016 | 325,304 |
Abandonment Expense | 156,809 | 189,259 |
General and administrative | 2,785,687 | 3,706,182 |
Provision for doubtful debts | 175,000 | 75,000 |
Total operating expenses | 17,918,345 | 12,651,439 |
LOSS FROM OPERATIONS | (5,255,480) | (2,592,720) |
Interest expense, net | (3,765,652) | (1,715,342) |
Realized loss on derivative instruments | (968,418) | (1,775,728) |
Unrealized gain(loss) on derivative instruments | 1,425,634 | (946,438) |
Gain on sale of assets | 120,000 | 178,407 |
Income from forfeiture of non-refundable deposit | 1,000,000 | |
Other | 247,941 | 80,899 |
LOSS BEFORE INCOME TAXES | (7,195,975) | (6,770,922) |
Income tax benefit | 47,944 | 732,056 |
NET LOSS | (7,148,031) | (6,038,866) |
OTHER COMPREHENSIVE LOSS: | ||
Foreign currency translation loss | (11,152) | (45,461) |
Total comprehensive loss for the period | $ (7,159,183) | $ (6,084,327) |
NET LOSS PER COMMON SHARE: | ||
Basic and diluted - per share | $ (0.02) | $ (0.02) |
Weighted average common shares outstanding: | ||
Basic and diluted shares | 328,300,044 | 328,300,044 |
Oil [Member] | ||
OPERATING REVENUES: | ||
Total oil and gas income | $ 12,391,536 | $ 9,931,065 |
Natural Gas [Member] | ||
OPERATING REVENUES: | ||
Total oil and gas income | 257,895 | 118,783 |
Other Liquids [Member] | ||
OPERATING REVENUES: | ||
Total oil and gas income | $ 13,434 | $ 8,871 |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Stockholders' Deficit - USD ($) | Issued Capital [Member] | Accumulated Deficit [Member] | Accumulated Other Comprehensive Income [Member] | Total |
Beginning Balance, value at Jun. 30, 2017 | $ 106,390,864 | $ (104,222,925) | $ 892,017 | $ 3,059,956 |
Net loss | (6,038,866) | (6,038,866) | ||
Foreign currency translation loss | (45,461) | (45,461) | ||
Total comprehensive loss for the period | (6,038,866) | (45,461) | (6,084,327) | |
Stock based compensation | 352,303 | 352,303 | ||
Ending Balance, value at Jun. 30, 2018 | 106,743,167 | (110,261,791) | 846,556 | (2,672,068) |
Net loss | (7,148,031) | (7,148,031) | ||
Foreign currency translation loss | (11,152) | (11,152) | ||
Total comprehensive loss for the period | (7,148,031) | (11,152) | (7,159,183) | |
Stock based compensation | ||||
Ending Balance, value at Jun. 30, 2019 | $ 106,743,167 | $ (117,409,822) | $ 835,404 | $ (9,831,251) |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Cash Flows from Operating Activities: | ||
Net loss | $ (7,148,031) | $ (6,038,866) |
Adjustments to reconcile net loss to net cash provided by (used) for operating activities: | ||
Depreciation, depletion and amortization | 1,824,014 | 1,237,989 |
Accretion of discount on asset retirement obligations | 561,950 | 250,783 |
Exploration and evaluation assets written off | 325,290 | |
Unrealized (gain) loss on derivative instruments | (1,425,634) | 946,438 |
Share based compensation | 352,303 | |
Amortization of debt discount | 1,390,564 | 32,808 |
Settlement of asset retirement obligations | (295,282) | (289,896) |
Provision for bad debt expense | 175,000 | 75,000 |
Write-off of uncollectible accounts receivable's | 22,346 | |
Oil inventory | 219,288 | |
Gain on sale of properties | (120,000) | (178,407) |
Deferred tax asset | (47,944) | (732,056) |
Changes in operating assets and liabilities: | ||
Accounts receivables | (270,590) | (284,023) |
Prepayments | 137,342 | (82,823) |
Accounts payable | (376,509) | 4,702,429 |
Accrued liabilities | (38,979) | 268,785 |
Deposits | 24,999 | 156,535 |
Net cash (used in) provided from operating activities | (5,367,466) | 742,289 |
Cash Flows from Investing Activities: | ||
Proceeds from sale of oil and gas properties | 120,000 | 105,396 |
Payments for oil and gas properties | (1,588,102) | (414,480) |
Payments for exploration and evaluation, net | (54,212) | |
Payments for furniture and fittings | (31,379) | |
Net cash flows used in investing activities | (1,468,102) | (394,675) |
Cash Flows from Financing Activities: | ||
Proceeds from borrowings | 33,561,707 | 450,000 |
Repayments of borrowings | (23,929,264) | (35,000) |
Payments for costs associated with borrowings | (1,390,565) | |
Net cash provided by financing activities | 8,241,878 | 415,000 |
Net increase in cash and equivalents and restricted cash | 1,406,310 | 762,614 |
Cash and equivalents, beginning of period and restricted cash | 1,376,676 | 628,778 |
Effect of exchange rate changes on cash and equivalents | (8,499) | (14,716) |
Cash, restricted cash and equivalents, end of period | 2,774,487 | 1,376,676 |
Cash paid for interest | (2,458,205) | (1,715,342) |
Cash paid for taxes |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Jun. 30, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
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 realization of assets and settlement of liabilities in the normal course of business. The Company incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. At June 30, 2019 , the Company’s total current liabilities of $43.3 million exceed its total current assets of $4.8 million. Its ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and /or raising further capital. These factors raise substantial doubt over the Company’s ability to continue as a going concern and therefore whether it will realize its assets and extinguish its liabilities in the normal course of business and at the amounts stated in the financial report. At June 30, 2019, the Company was in breach of several of its covenants related to the Credit Agreement (defined in Note 8 – Credit Facility), resulting in borrowings payable of $33.5 million being classified as current liabilities. It is currently negotiating with the Lender in an effort to obtain a waiver for the breach. As of the date of this report, no waiver has been received . The Company is currently negotiating with a prospective party to divest its oil and gas assets , as well as, continuing to execute on its drilling and development plan, which it believes will result in proceeds that will sufficiently cover the Company’s obligations to the Lender and its other creditors. Although the Company is confident it will be able to successfully recognize amounts in excess of the carrying value of its oil and gas assets as a result of its ultimate divestment or , alternatively , through the successful development of its Foreman Butte project , there can be no assurances made that the Company will be able to successfully execute these plans. G iven the current financial situation it is possible that the Company may be forced to accept terms on these transactions that are less favorable than would be otherwise available. 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. Certain amounts in prior year financial statements have been reclassified to current year presentation, and the reclassification had no impact on net loss. Use of Estimates. The preparation of financial statements in conformity with 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 (“DD&A”); (4) asset retirement obligations (“ARO”); (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 expenditures. 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 (“NGL”). 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. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers ( Topic 606 ) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective July 1, 201 8 , the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. 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, 2019 or 2018. 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. Restricted cash. ASU 2016-18 , Statement of Cash Flows (Topic 230): Restricted Cash) This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The Company has adopted this standard. In accordance with the terms of our Credit Agreement, the C o mpany is required to have a Capital Reserve Amount (as defined in the Credit Agreement) equal to $1.0 million and a Debt Service Reserve Amount (as defined in the Credit Agreement) equal to approximately $1.1 million. These amounts are carried on the balance sheet as Restricted Cash - Required reserve amounts related to Credit Agreement . Accounts Receivable. The components of accounts receivable include the following: June 30 2019 2018 Oil and natural gas sales $ 1,538,451 $ 1,159,905 Cost recovery from partners 650,885 768,281 Less provision for doubtful debts (250,000) (75,000) Other 42,787 55,693 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018 $ 1,982,123 $ 1,908,879 The Company's accounts receivable’s result from; (i) oil and natural gas sales to oil and intrastate gas pipeline companies, (ii) billings to joint working interest partners in properties operated by the Company, and (iii) settlements for derivatives with our counter-party. The Company's trade and accrued production receivables are primarily from operated oil and gas properties. A portion of its oil and natural gas revenues are from non-operated oil and gas properties, whereby, the operators of the various projects negotiate the sale of oil and gas to third parties on the Company’s behalf. Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable. At June 30, 2019 and 2018, the Company recorded an allowance for accounts receivable of $175,000 and $75,000 , respectively. Oil and Gas Properties. Oil and gas properties and equipment consist of the following at June 30: 2019 2018 Proved properties, net of impairment $ 39,666,294 $ 38,110,237 Work in progress 40,319 8,271 Less accumulated depreciation, depletion and amortization (9,491,784) (7,697,667) $ 30,214,829 $ 30,420,841 Unproved acreage $ - $ - The Company accounts for its oil and natural 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 costs 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 . 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 years ended June 30, 2019, and 2018, we expensed $0 and $0.2 million, respectively, in deferred exploration expense. Impairment The Company had no impairment charges for the years ended June 30, 2019, and 2018. 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, 2019, and 2018, was approximately $30,000 and $85,000 , respectively. Other property and equipment consist of the following at June 30: 2019 2018 Furniture, fittings and equipment $ 930,173 $ 1,017,879 Less accumulated depreciation (755,242) (775,057) $ 174,931 $ 242,822 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. Los s per Share. Basic loss per share are calculated by dividing net 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 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. Year ended June 30, 2019 2018 Net loss: $ (7,148,031) $ (6,038,866) Basic and diluted weighted average common shares outstanding 328,300,044 328,300,044 Basic and diluted loss per common share – cents per share (0.02) (0.02) 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 Company 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 exceed the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. Recently Issued Accounting Pronouncements ASU 2016-02, Leases (Topic 842) In January 2016, ASC 842 was issued, which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. ASC 842 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments, as a right of use asset and respective liability. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss. The Company operates predominantly as a lessee. The standard will affect primarily the accounting for its operating leases, with no significant impact expected for its finance leases. The new lease standard is effective for the Company on July 1, 2019, and will be adopted effective on that date using the simplified cumulative catch-up method. This adoption method will allow the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at July 1, 2019, will be made for the difference between the right of use asset and liability recorded. In addition, lease incentives will be rolled into the respective right of use asset, rather than recorded as a deferral. Upon adoption of the new standard, the Company intends to elect to apply hindsight in assessing the lease term, and to grandfather previous conclusions reached as to whether existing contracts are or contain leases. It continues to evaluate other practical elections, which may apply to individual asset classes and to portfolios of leases that contain similar characteristics. As of June 30, 2019, the Company had approximately $220,000 of contractual obligations related to its non-cancelable leases. The Company is in the process of evaluating those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASC 842. It is also in the process of implementing changes to its accounting policies, internal controls, and financial statements as a result of adoption of this standard. The Company will continue to assess the additional disclosures that will be required upon implementation of the standard. |
Revenue From Contracts With Cus
Revenue From Contracts With Customers | 12 Months Ended |
Jun. 30, 2019 | |
Revenue From Contracts With Customers [Abstract] | |
Revenue From Contracts With Customers | 2. REVENUE FROM CONTRACTS WITH CUSTOMERS The Company recognizes its share of revenue from the sale of produced oil, gas, and NGLs in its Rocky Mountain regions. Oil, gas, and NGL production revenue presented within the accompanying statements of operations is reflective of the revenue generated from contracts with customers. The tables below present the disaggregation of oil, gas, and NGL production revenue by product type for fiscal years ended June 30 : 2019 2018 Oil sales $ 12,391,536 $ 9,931,065 Gas sales 257,895 118,783 Other liquids 13,434 8,871 Total oil and gas income $ 12,662,865 $ 10,058,719 The Company recognizes oil, gas, and NGL production revenue at the point in time when control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of transportation, gathering, processing, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the oil, gas, and NGL production expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGL production revenue. The Company has two categories under which oil, gas, and NGL production revenue is generated , as summarized below: 1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead. 2) The Company sells unprocessed gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed gas under these arrangements are reflected as gas production revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred. Significant judgments made in applying the guidance in ASC Topic 606, Revenue from Contracts with Customers relate to the point in time when control transfers to customers in gas processing arrangements with midstream processors. The Company does not believe that significant judgments are required with respect to the determination of the transaction price, including amounts that represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not consider estimates of variable consideration to be constrained. The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the Company has an ownership interest. The performance obligations are considered satisfied upon control transferring to a customer at the wellhead or inlet of the midstream processor’s processing facility, or other contractually specified delivery point. The time period between production and satisfaction of performance obligations is generally less than one day; thus, there are no material unsatisfied or partially unsatisfied performance obligations at the end of the reporting period. Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received 30 to 90 days after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. Estimated revenue due to the Company is recorded within accounts receivable on the accompanying balance sheets until payment is received. The accounts receivable balances from contracts with customers within the accompanying balance sheets as of June 30, 2019, and 2018 , were $1.5 million and $1.0 million, respectively. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received from the purchaser. Revenue recognized for the fiscal year ended June 30, 2019 , that related to performance obligations satisfied in prior reporting periods, was immaterial. |
Hedging And Derivative Financia
Hedging And Derivative Financial Instruments | 12 Months Ended |
Jun. 30, 2019 | |
Hedging And Derivative Financial Instruments [Abstract] | |
Hedging And Derivative Financial Instruments | 3. HEDGING AND DERIVATIVE FINANCIAL INSTRUMENTS Commodity Derivative Agreements. The Company utilizes swap and collar option contracts to hedge the effect of price changes on a portion of its future oil and natural gas production. The objective of the Company’s hedging activities and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they also may limit future revenues from favorable price movements. The Company may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of the Company’s existing positions. The Company may use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional unmitigated commodity price risk. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are with a single major oil company with no history of default with the Company. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. 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 accumulated other comprehensive income for those commodity derivatives that would qualify as cash flow hedges. All derivative instruments are recorded on the balance sheet at fair value. At June 30, 2019, the Company’s commodity derivative contracts consisted of collars and fixed price swaps, which are described below: Collar Collars contain a fixed floor price (put) and fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price rather than the market price. If the market price is between the call and the put strike price, no payments are due from either party. Fixed price swap The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. All of the Company’s derivative contracts are with the same counterparty and are shown on a net basis on the Balance Sheet. The Company’s counterparty has entered into an inter-creditor agreement with AEP I FINCO LLC, the Company’s lender. As such no collateral is required by the counterparty. During the third quarter of fiscal year ending June 30, 2019, the company entered into a series of swaps and costless collars for its oil and natural gas production. As of June 30, 2019, the Company had commodity derivative instruments outstanding through the first quarter of 2023, as summarized in the table below. Asset (liability) Price per Bbl – WTI Estimated Floor Ceiling Swap Fair Value Year $ $ $ Units (Bbl) $ Crude Oil Derivatives 2019 N/A N/A 55.75 – 58.10 109,000 (118,762) 2020 N/A N/A 55.39 – 57.05 200,000 38,418 2021 N/A N/A 54.03 – 55.70 182,000 118,142 2022 N/A N/A 53.15 – 55.70 163,000 134,254 2023 N/A N/A 53.46 – 55.70 39,000 20,802 N/A N/A 693,000 192,854 Price per Mcf – Henry Hub Estimated Floor Ceiling Swap Units (Mcf) Fair Value Year $ $ $ $ Natural Gas Derivatives 2019 $ 2.60 $ 2.80 $ - 30,000 6,875 2020 $ 2.60 $ 2.80 $ - 63,900 7,709 2021 $ 2.60 $ 2.80 $ - 57,600 5,122 2022 $ 2.60 $ 2.80 $ - 51,300 3,676 2023 $ 2.60 $ 2.80 $ - 11,700 (1,397) 214,500 21,985 Derivative Assets and Liabilities Fair Value. The Company’s commodity derivatives are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities. The Company does not designate its derivative commodity contracts as hedging instruments. The fair value of the derivative commodity contracts was a net asset of $0.2 million at June 30, 2019, and a net liability of $1.2 million at June 30, 2018. The following tables detail the fair value of derivatives recorded in the accompanying balance sheets, by category: As of June 30, 2019 Derivative Assets Derivative Liabilities Balance Sheet Balance Sheet Classification Fair Value Classification Fair Value Commodity contracts Current assets - Current liabilities 150,703 Commodity contracts Noncurrent assets 365,542 Noncurrent liabilities - Total commodity contracts 365,542 150,703 As of June 30, 2018 Derivative Assets Derivative Liabilities Balance Sheet Balance Sheet Classification Fair Value Classification Fair Value Commodity contracts Current assets - Current liabilities 1,210,795 Commodity contracts Noncurrent assets - Noncurrent liabilities - Total commodity contracts - 1,210,795 Offsetting of Derivative Assets and Liabilities. As of June 30, 2019, and 2018, all derivative instruments held by the Company were subject to a master netting arrangement with one financial institution. In general, the terms of the Company’s agreement provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreement also provides that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying balance sheets. The Company recognizes all gains and losses from changes in commodity derivative fair values immediately in earnings rather than deferring any such amounts in accumulated other comprehensive income (loss). The Company had no derivatives designated as hedging instruments for the fiscal years ended June 30, 2019, and 2018. The following table summarizes the components of the net derivative gain ( loss ) line item presented in the accompanying statements of operations: For the Years Ended June 30, 2019 2018 Unrealized gain (loss) on derivatives 1,425,634 (946,438) Realized gain (loss) on derivatives (968,418) (1,775,728) Total gain (loss) on derivatives 457,216 (2,722,166) See Note 4 for additional fair value disclosures about the Company’s oil and gas derivatives. Credit Related Contingent Features. As of June 30, 2019, and through the filing of this report, all of the Company’s derivative counterparties were members of the Company’s Credit Agreement lender group. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Jun. 30, 2019 | |
Fair Value Measurements [Abstract] | |
Fair Value Measurements | 4. FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received in the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. The Company classifies fair value balances based on the observability of those inputs. The FASB has established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The three levels of the fair value hierarchy are as follows: Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2—Pricing inputs are other than quoted prices in active markets included in level 1, but are either directly or indirectly observable as of the reported date and for substantially the full term of the instrument. Inputs may include quoted prices for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value as of June 30, 2019 and 2018. Fair Value at June 30, 2019 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash, restricted cash and cash equivalents $ 2,774,487 $ - $ - $ - $ 2,774,487 Derivative Instruments - 16,889 - (16,889) - Non Current Assets: Derivative Instruments - 377,845 - (12,303) 365,542 Current Liabilities Derivative Instruments - (167,592) - 16,889 (150,703) Non Current Liabilities: Derivative Instruments (12,303) - 12,303 - Fair Value at June 30, 2018 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 1,376,676 $ - $ - $ - $ 1,376,676 Derivative Instruments - 4,218 - (4,218) - Non Current Assets: Derivative Instruments - - - - - Current Liabilities Derivative Instruments - 1,215,013 - (4,218) 1,210,795 Non Current Liabilities: Derivative Instruments - - - (1) Netting In accordance with the Company’s standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated. The following methods and assumptions were used to estimate the fair value of the assets and liabilities in the table above: Commodity Derivative Contracts. The Company’s commodity derivative instruments consisted of collars and swap contracts for oil and natural gas. The Company values the derivative contracts using industry standard models, based on an income approach, which considers various assumptions including quoted forward prices and contractual prices for the underlying commodities, time value and volatility factors, as well as other relevant economic measures. Substantially all of the assumptions can be observed throughout the full term of the contracts, can be derived from observable data or are supportable by observable levels at which transactions are executed in the marketplace and are therefore designated as level 2 within the fair value hierarchy. The discount rates used in the assumptions include consideration of non-performance risk. The Company accounts for its commodity derivatives at fair value (see Note 3) on a recurring basis. Fair Value of Financial Instruments. The Company’s financial instruments consist primarily of cash and cash equivalents, restricted cash, accounts receivable and payable, investments and derivatives (discussed above). The carrying values of cash equivalents and accounts receivable and payable are representative of their fair values due to their short–term maturities. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. The Company also applies fair value accounting guidance to measure non–financial assets and liabilities such as business acquisitions proved oil and gas properties, and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. These items are primarily valued using the present value of estimated future cash inflows and/or outflows. Given the unobservable nature of these inputs, they are deemed to be Level 3. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. The Company utilizes the discounted cash flow method; estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operational costs, and a risk–adjusted discount rate. The fair value measurement was based on Level 3 inputs. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Jun. 30, 2019 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | 5. ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations primarily represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing and shut–in properties at the end of their productive lives in accordance with applicable state and federal laws. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The significant inputs used to calculate such liabilities include estimates of costs to be incurred; the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted using the units–of–production method. The following table summarizes the activities for the Company’s asset retirement obligations for the years ended June 30: 2019 2018 Asset retirement obligations at beginning of period $ 3,344,112 $ 3,240,007 Liabilities incurred or acquired - - Liabilities settled (295,282) (73,667) Disposition of properties - (73,011) Accretion expense 561,950 250,783 Asset retirement obligations at end of period 3,610,780 3,344,112 Long-term asset retirement obligations $ 3,610,780 $ 3,344,112 Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4 % and 13 %. |
Income Taxes
Income Taxes | 12 Months Ended |
Jun. 30, 2019 | |
Income Taxes [Abstract] | |
Income Taxes | 6. INCOME TAXES The Company accounts for income taxes under the asset and liability approach prescribed by GAAP, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company’s consolidated financial statements or tax returns. The Company’s income tax provision (benefit) is composed of the following: June 30 2019 2018 Current: Federal $ - $ - State 200 - 200 - Deferred: Federal (48,144) (732,056) State - - Total income tax benefit $ (47,944) $ (732,056) A reconciliation of the income tax provision (benefit) computed by applying the Australian federal statutory rate of 30 % to the Company’s income tax provision (benefit) is as follows: June 30 2019 2018 Income tax expense (benefit) at federal statutory rate $ (1,979,000) $ (1,956,277) Effect of Permanent Differences and Other-US 121,000 115,616 State Taxes, Net of Federal Benefit (600,000) (123,694) Change in Valuation Allowance 1,692,000 (10,104,596) Change in Tax Rate 342,000 11,207,430 US income taxed at a different rate 432,000 116,777 Other (55,944) 12,688 Total income tax benefit $ (47,944) $ (732,056) The components of the deferred tax assets and (liabilities) are as follows: June 30 2019 2018 Deferred income tax assets: Net operating losses $ 26,450,000 $ 23,674,591 Asset retirement obligation 807,000 737,876 Abandonment limitation - 544,869 Debt issuance costs 312,000 - AMT Credit 780,000 780,443 Provision for Annual Leave 50,000 51,837 Allowance For Doubtful Accounts 59,000 17,558 Share based comp 459,000 500,845 Hedge Liability - 283,458 Gross deferred tax assets $ 28,917,000 $ 26,591,477 Deferred income tax liabilities: Oil and gas property (2,085,000) (1,908,395) Hedge Liability (51,000) - Gross deferred tax liabilities $ (2,136,000) $ (1,908,395) Net deferred income tax assets (liabilities) 26,781,000 24,683,082 Valuation allowance (26,001,000) (23,951,026) Noncurrent deferred tax asset $ 780,000 $ 732,056 The Company has tax losses carried forward arising in Australia of $17.4 million. The benefit of these losses of $4.8 million will only be obtained in future years if: (i) the Parent Entity derive future assessable income of a nature and an amount sufficient to enable the benefit from the deduction for the losses to be realized; and (ii) the Parent Entity have complied and continue to comply with the conditions for deductibility imposed by law; and (iii) no changes in tax legislation adversely affect the Parent Entity in realizing the benefit from deduction for the losses. The Company has federal net operating tax losses in the United States of approximately $94.1 million. The 2000-2005 years are limited to $ 403,194 per year as a result of a change in ownership of the one of the subsidiaries which occurred in January 2005. NOLs generated after this ownership change are not limited due to any known ownership changes. If not utilized, the tax net operating losses will expire during the period from 2020 to 2038 . NOL's generated in 2019 do not expire and can be carried forward indefinitely. Of the $9.2 million available as of July 1, 2011, $4.0 million will never be utilized and will expire by June 2025 . In addition to the above-mentioned Federal carried forward losses in the United States, the Company also has approximately $52.9 million of State carried forward tax losses, with expiry dates between 2020 and 2039 . A deferred income tax asset in relation to these losses has not been recognized as realization of the benefit is not regarded as probable. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, Management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income. As of the current year end, the company does not believe the realizability of the deferred tax assets to be more likely than not except for AMT credits. As such, the company has a full valuation allowance offsetting the deferred tax asset, with the exception of the valuation allowance related to the refundable AMT Credit which is now realizable due to the tax law changes in the Tax Cuts and Jobs Act passed during 2018. The Company adopted the uncertainty provision of FASB ASC Topic 740, "Income Taxes" and has analyzed filing positions in all federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in this jurisdiction. Most uncertain tax positions relate primarily to timing differences and management does not believe any such uncertain tax positions will materially impact the Company's effective tax rate in future periods. The Company anticipates that no additional uncertain tax positions will be recognized within the next twelve months. Our policy is to recognize any interest and penalties related to the unrecognized tax benefits in income tax expense. In our major tax jurisdictions, the earliest years remaining open to examination are as follows US - 6/30/1996 due to the usage of net operating losses from that period. If recognized, these uncertain tax positions would impact the Company's effective income tax rate. The company currently has no unrecognized positions. |
Common Stock
Common Stock | 12 Months Ended |
Jun. 30, 2019 | |
Common Stock [Abstract] | |
Common Stock | 7. COMMON STOCK June 30, 2019 2018 328,300,044 ordinary fully paid shares including shares to be issued $ 106,743,167 $ 106,743,167 Movements in contributed equity for the year 2019 2018 No. of shares $ No. of shares $ Opening balance 328,300,044 106,743,167 328,300,044 106,390,864 Capital raising (i) - - - - Shares issued upon exercise of options (ii) - - - - Share based compensation - - - 352,303 Transaction costs incurred - - - - Shares on issue at balance date 328,300,044 106,743,167 328,300,044 106,743,167 |
Credit Facility
Credit Facility | 12 Months Ended |
Jun. 30, 2019 | |
Credit Facility [Abstract] | |
Credit Facility | 8. CREDIT FACILITY June 30, 2019 2018 Credit facility at beginning of period $ 23,867,557 $ 23,419,749 Cash advanced under Credit Agreement 33,561,707 450,000 Repayments (23,929,264) (2,192) Credit facility at end of period $ 33,500,000 $ 23,867,557 Funds available for drawdown under the facility - - On April 9, 2019 , the C ompany closed a $33.5 million refinancing with AEP I FINCO LLC (“Lender”) , as administrative agent, and certain other financial institutions (the “Credit Agreement”). The proceeds of the Credit Agreement were used to retire the C ompany ’s previous credit facility of $23.9 million, repay outstanding creditors, royalty and working interest owners and provide working capital to pursue its infill development drilling program. In conjunction with the closing of the Credit Agreement, the C ompany paid $1.4 million in deferred borrowing costs. The Credit Agreement is secured by certain of the C ompany ’s oil and gas properties and has a 5 -year term with a maturity date on 09 April 2024 . Interest on the Credit Facility accrues at a rate equal to LIBOR plus a margin of 10.5% and is payable on the last day of each interest period. The effective interest rate at for fiscal year ended June 30, 2019, had a range between 5.0% and 13.0% . Under the Credit Facility, the C ompany is required to maintain the following financial ratios: · a maximum Leverage Ratio, consisting of Consolidated Total Debt to Consolidated EBITDAX (as defined in the Credit Agreement) not to; (i) exceed 4.75 to 1.00 as of the last day of Fiscal Quarter (as defined in the Credit Facility) ending June 30, 2019 , (ii) exceed 4.00 to 1.00 as of the last day of any Fiscal Quarter beginning after June 30, 2019 , but ending on or before 31 March 2020; (iii) for Fiscal Quarters ending June 30, 2020, and September 30, 2020, to exceed 3.50 to 1.00, and (iv) for all Fiscal Quarters thereafter, exceed 3.00 to 1.00; · a minimum Current Ratio, consisting of consolidated current assets (as defined in the Credit Agreement) to consolidated current liabilities (as defined in the Credit Agreement), of not less than 1.0 to 1.0 as of the last day of any Fiscal Quarter; · an Asset Coverage Ratio, consisting of Modified Proved NPV (as defined in the Credit Agreement) to Consolidated Total Debt, beginning with Fiscal Quarter ending June 30, 2019 , (i) to be less than 2.0 to 1.0 during any Fiscal Quarter ending before March 31, 2021, and (ii) for all Fiscal Quarters thereafter, to be less than 2.50 to 1.00; · an Asset Coverage Ratio (PDP), consisting of Modified Proved NPV for PDP to Consolidated Total Debt, to be (i) less than 1.10 to 1.00 for Fiscal Quarter ending June 30, 2019 , (ii) for Fiscal Quarters ending on September 30, 2019 and December 31, 2019, to be less than 1.15 to 1.00, (iii) during the Fiscal Quarter ended March 31, 2020, to be less than 1.25 to 1.00, (iv) for Fiscal Quarters ending on June 30, 2020, September 30, 2020, December 31, 2020, and March 31, 2021 to be less than 1.50 to 1.00, and (v) for all Fiscal Quarters thereafter, to be less than 1.75 to 1.00;a Fixed Charge Coverage Ratio, consisting of Consolidated EBITDAX for the Fiscal Quarter just ended, plus unrestricted cash and cash equivalents on the last day of the preceding Fiscal Quarter to Consolidated Fixed Charges (as defined in the Credit Facility) for the just ended Fiscal Quarter; (i) for the fiscal quarter ended June 30, 2019 , to be less than 1.35 to 1.00, and (ii) for all Fiscal Quarters thereafter, to be less than 1.40 to 1.00; and · the Company shall not make Capital Expenditures (as defined in the Credit Agreement) in any fiscal Quarter, beginning with the fiscal Quarter ended June 30, 2019 , that would cause the aggregate amount of all Capital Expenditures in such Fiscal Quarter to exceed by more than (i) 10% the amount of Capital Expenditures for such Fiscal Quarter set forth on the then current and Approved Acquisition and Development Plan (defined in the Credit Agreement), or (ii) 10% the amount of the Capital Expenditures set forth in the then-current and Acquisition and Development Plan in the aggregate. At June 30, 2019, the Company was not in compliance with certain financial covenants under the Credit Agreement, therefore, the total outstanding amount of the Credit Agreement has been categori z ed as a current liability and the deferred financing fees in the amount of $1.4 million, previously recorded as debt discount, have been expensed. Due to the Company’s recent breaches of the Credit Agreement, the Lender may declare an event of default and foreclose on some or all of the Company’s assets and/or accelerate the full amount of the $33.5 million loan plus all accrued and unpaid interest, prepayment penalties, fees and other lender costs and expenses. |
Share-Based Payments
Share-Based Payments | 12 Months Ended |
Jun. 30, 2019 | |
Share-Based Payments [Abstract] | |
Share-Based Payments | 9. SHARE-BASED PAYMENTS (all figures are in Australian dollars in this note unless noted otherwise) During the year ended June 30, 2011, the Company registered a Form S-8 with the Securities Exchange Commission. The Form S-8 is a registration statement used by U.S. public companies to register securities to be offered pursuant to employee benefit plans , in this case the ordinary shares issuable and reserved for issuance underlying the options which may be issued pursuant to the Samson Oil & Gas Limited Stock Option Plan were registered. All incentive options issued by the Company are valued using a Black-Scholes pricing model which requires inputs for the share price at grant date, exercise price, time to expiry, risk free interest rate, share price volatility and dividend yield. The risk - free interest rate is based on the interest rate applicable to Australian Government Bonds with a similar remaining life to the options on the day of grant. The dividend yield is the expected annual dividend yield over the expected life of the option. The volatility factors are based on historic volatility of the Company’s stock. Estimates of fair value are not intended to predict actual future events or the value ultimately realized by certain employees who receive stock options, and subsequent events are indicative of the reasonableness of the original fair value estimates. No options were issued during the fiscal years ended June 30, 2019, and 2018, as share-based payments. The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 2019 and 2018 (all values in AUD unless otherwise noted): 2019 2018 Weighted Aggregate Weighted Average Intrinsic Average Exercise Price Value of Exercise Price Number A$ A$ Number A$ Outstanding, start of period 314,500,000 0.057 - 411,033,246 0.0118 Granted - - - - - Exercised - - - - - Cancelled/expired - - - (96,533,246) 0.0380 Outstanding, end of period 314,500,000 0.057 - 314,500,000 0.0570 Exercisable, end of period 314,500,000 0.057 - 314,500,000 0.0570 (1) The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date. If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option. No options were exercised during 2018. Additional information related to options and warrants outstanding at June 30, 2019 are as follows: Options/Warrants Outstanding and Exercisable Weighted Average Range of Remaining Exercise Number Contractual Prices (A$) Outstanding Life - years $0.070 48,000,000 7.42 $0.055 266,500,000 7.42 314,500,000 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Jun. 30, 2019 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 10. RELATED PARTY TRANSACTIONS There were no related party transactions during the years ended June 30, 2019 and 2018. |
Commitments
Commitments | 12 Months Ended |
Jun. 30, 2019 | |
Commitments [Abstract] | |
Commitments | 1 1 . COMMITMENTS Leases –The Company has entered into a lease agreement for office space in Denver, Colorado. As of June 30, 2019, future minimum lease payments under this operating lease with remaining non– cancelable terms in excess of one year are as follows: Total 2020 2021 2022 2023 Thereafter Leases 219,643 103,616 107,080 8,947 - - |
Contingencies
Contingencies | 12 Months Ended |
Jun. 30, 2019 | |
Contingencies [Abstract] | |
Contingencies | 12. CONTINGENCIES Samson may be subject to various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, and claims for underpayment of royalties, property damage claims and contract actions. The Company records an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to its business operations is likely to have a material adverse effect on the company’s consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Jun. 30, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events | 13. SUBSEQUENT EVENTS On September 4, 2019, the Company received an administrative action brought by the Commission under North Dakota Century Code Chapters 38-08 and 28-32 (“NDIC). The notice makes claim to the status of certain shut-in wells and other location items operated by Samson . Samson submitted its formal response in September 2019, and has met with the NDIC concerning this matter and has presented the Company’s plan to address the administrative action. No final resolution or settlement has been entered into as of the filing of this report and the Company cannot reasonably estimate the amount of any potential penalties or fees that may be assessed against the Company at June 30, 2019, therefore, no accrual for potential contingent liabilities have been included in the Company’s financial statements. |
Supplemental Information On Oil
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations | 12 Months Ended |
Jun. 30, 2019 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations | 14. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES, INCLUSIVE OF DISCONTINUED OPERATIONS (UNAUDITED) Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by Netherland, Sewell & Associates, Inc. All of the Company’s reserves were located in the United States. Capitalized Costs Incurred. Costs incurred for oil and natural gas exploration, development and acquisition are summarized below. Year ended June 30, 2019 2018 Development 1,462,483 13,272 Undeveloped capitalized acreage - - Total costs incurred $ 1,462,483 $ 13,272 Oil and Gas Reserve Quantities. The reserve estimates presented below were made in accordance with GAAP requirements for disclosures about oil and gas producing activities and SEC rules for oil and gas reporting of reserve estimation and disclosure. Proved reserves are the estimated quantities of oil, gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and the price to be used is the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The table below presents a summary of changes in the Company’s estimated proved reserves for each of the years in the fiscal years ended June 30, 2019 , and 2018 . The Company engaged Netherland, Sewell & Associates, Inc. to audit internal engineering estimates for 10 0 percent of the Company’s total calculated proved reserve s PV-10 for each year presented. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Year ended June 30, 2019 Year ended June 30, 2018 Oil Gas Total Oil Gas Total Mbbls MMcf MBOE Mbbls MMcf MBOE Beginning of year 3,515 1,292 3,732 5,359 3,565 5,954 Revisions of previous quantity estimates * (361) (342) (419) (1,657) (2,258) (2,033) Extensions and discoveries - - - - - - Sale of reserves in place - - - - - - Acquisitions - - - - - - Production (224) (35) (230) (187) (15) (189) End of year 2,930 915 3,083 3,515 1,292 3,732 Proved developed producing reserves 2,930 915 3,083 2,663 623 2,768 Proved developed non producing * - - - 544 418 614 Proved undeveloped reserves * - - - 308 251 350 Total proved reserves 2,930 915 3,083 3,515 1,292 3,732 * Given the Company’s current financial condition there is no assurance that it will have the necessary financial resources available to meet the investment and operating criteria , as defined under SEC regulation, to execute the development plan necessary to include PDNP and PUD reserves in the Company’s reserve report . Standardized Measure of Discounted Future Net Cash Flows. The Company computes a standardized measure of future net cash flows (“Standardized Measure”) and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year - end estimated future reserve quantities. Estimated future income taxes are computed using the current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 1 0 percent annual discount factor. The impact of income taxes has not been included in the current or prior year , as the net operating losses and the tax basis of the assets exceed the future cash flows. Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the estimated proved reserves in place at the end of the period using year end costs and assuming continuation of existing economic conditions, plus Company overhead incurred by the central administrative office attributable to operating activities. The assumptions used to compute the Standardized Measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the Standardized Measure computations since these reserve quantity estimates are the basis for the valuation process. The following prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the Standardized Measure: The following table shows the estimated standardized measure of discounted future net cash flows relating to proved reserves (in US$’000’s): As at June 30, 2019 2018 Future cash inflows $ 166,709 $ 187,249 Future production costs (85,626) (99,620) Future development costs - (1,642) Future income taxes - - Future net cashflows 81,083 85,987 10 % discount (33,513) (38,325) Standardized measure of discounted future net cash flows relating to proved reserves $ 47,570 $ 47,662 Standardized Measure PV10 Future cash inflows $ 166,709 $ 97,805 Future production costs (85,626) (50,235) Future development costs - - Future income taxes - - Future net cash flows 81,083 47,570 10% annual discount (33,513) - Discounted future net cash flows $ 47,570 $ 47,570 The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 201 9 and June 30, 201 8 are as follows (in US$’000’s): Fiscal Year Ended June 30 2019 2018 Beginning of year $ 47,662 $ 65,262 Sales of oil and gas, net of production costs and taxes (321) (3,902) Extensions and discoveries, net of costs 396 - Purchases of reserves in place - - Sales of reserves in place - - Changes in prices and production costs 3,476 2,822 Revisions of previous quantity estimates and other (8,884) (10,088) Previously estimated development costs incurred - - Changes in estimated future development costs 502 (11,625) Accretion of discount 4,766 - Net changes in income taxes - 6,526 Changes in timing and other (27) (1,333) Balance at end of year $ 47,570 $ 47,662 The impact of income taxes has not been included in the current year as the Company’s net operating losses, the tax basis of oil and gas assets and future expected deductions, exceed the future cash flows. |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended |
Jun. 30, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
Description Of Operations | 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 | Going concern. These financial statements have been prepared on the going concern basis, which contemplates the continuity of normal business activities and the realization of assets and settlement of liabilities in the normal course of business. The Company incurred a net loss of $7.2 million and had net cash outflows from operating activities of $5.4 million for the year ended June 30, 2019. At June 30, 2019 , the Company’s total current liabilities of $43.3 million exceed its total current assets of $4.8 million. Its ability to continue as a going concern is dependent on the re-negotiation of debt, the sale of assets and /or raising further capital. These factors raise substantial doubt over the Company’s ability to continue as a going concern and therefore whether it will realize its assets and extinguish its liabilities in the normal course of business and at the amounts stated in the financial report. At June 30, 2019, the Company was in breach of several of its covenants related to the Credit Agreement (defined in Note 8 – Credit Facility), resulting in borrowings payable of $33.5 million being classified as current liabilities. It is currently negotiating with the Lender in an effort to obtain a waiver for the breach. As of the date of this report, no waiver has been received . The Company is currently negotiating with a prospective party to divest its oil and gas assets , as well as, continuing to execute on its drilling and development plan, which it believes will result in proceeds that will sufficiently cover the Company’s obligations to the Lender and its other creditors. Although the Company is confident it will be able to successfully recognize amounts in excess of the carrying value of its oil and gas assets as a result of its ultimate divestment or , alternatively , through the successful development of its Foreman Butte project , there can be no assurances made that the Company will be able to successfully execute these plans. G iven the current financial situation it is possible that the Company may be forced to accept terms on these transactions that are less favorable than would be otherwise available. |
Comparatives | Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). |
Principles Of Consolidation | 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. Certain amounts in prior year financial statements have been reclassified to current year presentation, and the reclassification had no impact on net loss. |
Use Of Estimates | Use of Estimates. The preparation of financial statements in conformity with 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 (“DD&A”); (4) asset retirement obligations (“ARO”); (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 expenditures. 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 | 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 (“NGL”). 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 | Revenue Recognition and Gas Imbalances. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers ( Topic 606 ) (“ASU 2014-09”). Under the new standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. The standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The FASB issued several additional ASUs related to ASU 2014-09 that provide clarified implementation guidance and deferred the effective date of ASU 2014-09. Effective July 1, 201 8 , the Company adopted ASU 2014-09 and all related ASUs using the modified retrospective transition method, which was applied to all active contracts as of the effective date. The adoption of ASU 2014-09 did not result in a change to current or prior period results nor did it result in a material change to the Company’s business processes, systems, or controls. However, upon adoption, the Company expanded its disclosures to comply with the disclosure requirements of ASU 2014-09. Please refer to Note 2 - Revenue from Contracts with Customers for additional discussion. 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, 2019 or 2018. |
Cash And Cash Equivalents | 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. |
Restricted Cash | Restricted cash. ASU 2016-18 , Statement of Cash Flows (Topic 230): Restricted Cash) This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The Company has adopted this standard. In accordance with the terms of our Credit Agreement, the C o mpany is required to have a Capital Reserve Amount (as defined in the Credit Agreement) equal to $1.0 million and a Debt Service Reserve Amount (as defined in the Credit Agreement) equal to approximately $1.1 million. These amounts are carried on the balance sheet as Restricted Cash - Required reserve amounts related to Credit Agreement . |
Accounts Receivable | Accounts Receivable. The components of accounts receivable include the following: June 30 2019 2018 Oil and natural gas sales $ 1,538,451 $ 1,159,905 Cost recovery from partners 650,885 768,281 Less provision for doubtful debts (250,000) (75,000) Other 42,787 55,693 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018 $ 1,982,123 $ 1,908,879 The Company's accounts receivable’s result from; (i) oil and natural gas sales to oil and intrastate gas pipeline companies, (ii) billings to joint working interest partners in properties operated by the Company, and (iii) settlements for derivatives with our counter-party. The Company's trade and accrued production receivables are primarily from operated oil and gas properties. A portion of its oil and natural gas revenues are from non-operated oil and gas properties, whereby, the operators of the various projects negotiate the sale of oil and gas to third parties on the Company’s behalf. Collectability is dependent upon the financial wherewithal of each entity and is influenced by the general economic conditions of the oil and gas industry. The Company records an allowance for doubtful accounts on a case by case basis once there is evidence that collection is not probable. At June 30, 2019 and 2018, the Company recorded an allowance for accounts receivable of $175,000 and $75,000 , respectively. |
Oil And Gas Properties | Oil and Gas Properties. Oil and gas properties and equipment consist of the following at June 30: 2019 2018 Proved properties, net of impairment $ 39,666,294 $ 38,110,237 Work in progress 40,319 8,271 Less accumulated depreciation, depletion and amortization (9,491,784) (7,697,667) $ 30,214,829 $ 30,420,841 Unproved acreage $ - $ - The Company accounts for its oil and natural 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 costs 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 . 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 years ended June 30, 2019, and 2018, we expensed $0 and $0.2 million, respectively, in deferred exploration expense. |
Impairment | Impairment The Company had no impairment charges for the years ended June 30, 2019, and 2018. |
Other Property And Equipment | 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, 2019, and 2018, was approximately $30,000 and $85,000 , respectively. Other property and equipment consist of the following at June 30: 2019 2018 Furniture, fittings and equipment $ 930,173 $ 1,017,879 Less accumulated depreciation (755,242) (775,057) $ 174,931 $ 242,822 |
Derivative Financial Instruments | 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 | 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 | 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 | 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. |
Loss Per Share | Loss per Share. Basic loss per share are calculated by dividing net 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 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. Year ended June 30, 2019 2018 Net loss: $ (7,148,031) $ (6,038,866) Basic and diluted weighted average common shares outstanding 328,300,044 328,300,044 Basic and diluted loss per common share – cents per share (0.02) (0.02) |
Stock-Based Compensation | 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 | 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 Company 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 | 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 exceed the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. |
Recently Issued Accounting Pronouncements | Recently Issued Accounting Pronouncements ASU 2016-02, Leases (Topic 842) In January 2016, ASC 842 was issued, which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. ASC 842 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments, as a right of use asset and respective liability. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss. The Company operates predominantly as a lessee. The standard will affect primarily the accounting for its operating leases, with no significant impact expected for its finance leases. The new lease standard is effective for the Company on July 1, 2019, and will be adopted effective on that date using the simplified cumulative catch-up method. This adoption method will allow the presentation of previous comparative periods to remain unchanged, and an adjustment to the opening balance of retained earnings at July 1, 2019, will be made for the difference between the right of use asset and liability recorded. In addition, lease incentives will be rolled into the respective right of use asset, rather than recorded as a deferral. Upon adoption of the new standard, the Company intends to elect to apply hindsight in assessing the lease term, and to grandfather previous conclusions reached as to whether existing contracts are or contain leases. It continues to evaluate other practical elections, which may apply to individual asset classes and to portfolios of leases that contain similar characteristics. As of June 30, 2019, the Company had approximately $220,000 of contractual obligations related to its non-cancelable leases. The Company is in the process of evaluating those contracts as well as other existing arrangements to determine if they qualify for lease accounting under ASC 842. It is also in the process of implementing changes to its accounting policies, internal controls, and financial statements as a result of adoption of this standard. The Company will continue to assess the additional disclosures that will be required upon implementation of the standard. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Summary Of Significant Accounting Policies [Abstract] | |
Schedule Of Components Of Accounts Receivable | June 30 2019 2018 Oil and natural gas sales $ 1,538,451 $ 1,159,905 Cost recovery from partners 650,885 768,281 Less provision for doubtful debts (250,000) (75,000) Other 42,787 55,693 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2019 and 2018 $ 1,982,123 $ 1,908,879 |
Schedule Of Oil And Gas Properties And Equipment | 2019 2018 Proved properties, net of impairment $ 39,666,294 $ 38,110,237 Work in progress 40,319 8,271 Less accumulated depreciation, depletion and amortization (9,491,784) (7,697,667) $ 30,214,829 $ 30,420,841 Unproved acreage $ - $ - |
Schedule Of Other Property And Equipment | 2019 2018 Furniture, fittings and equipment $ 930,173 $ 1,017,879 Less accumulated depreciation (755,242) (775,057) $ 174,931 $ 242,822 |
Schedule Of Earnings Per Share, Basic And Diluted | Year ended June 30, 2019 2018 Net loss: $ (7,148,031) $ (6,038,866) Basic and diluted weighted average common shares outstanding 328,300,044 328,300,044 Basic and diluted loss per common share – cents per share (0.02) (0.02) |
Revenue From Contracts With C_2
Revenue From Contracts With Customers (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Revenue From Contracts With Customers [Abstract] | |
Disaggregation of Revenue | 2019 2018 Oil sales $ 12,391,536 $ 9,931,065 Gas sales 257,895 118,783 Other liquids 13,434 8,871 Total oil and gas income $ 12,662,865 $ 10,058,719 |
Hedging And Derivative Financ_2
Hedging And Derivative Financial Instruments (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Hedging And Derivative Financial Instruments [Abstract] | |
Schedule Of Open Derivative Contracts | Asset (liability) Price per Bbl – WTI Estimated Floor Ceiling Swap Fair Value Year $ $ $ Units (Bbl) $ Crude Oil Derivatives 2019 N/A N/A 55.75 – 58.10 109,000 (118,762) 2020 N/A N/A 55.39 – 57.05 200,000 38,418 2021 N/A N/A 54.03 – 55.70 182,000 118,142 2022 N/A N/A 53.15 – 55.70 163,000 134,254 2023 N/A N/A 53.46 – 55.70 39,000 20,802 N/A N/A 693,000 192,854 Price per Mcf – Henry Hub Estimated Floor Ceiling Swap Units (Mcf) Fair Value Year $ $ $ $ Natural Gas Derivatives 2019 $ 2.60 $ 2.80 $ - 30,000 6,875 2020 $ 2.60 $ 2.80 $ - 63,900 7,709 2021 $ 2.60 $ 2.80 $ - 57,600 5,122 2022 $ 2.60 $ 2.80 $ - 51,300 3,676 2023 $ 2.60 $ 2.80 $ - 11,700 (1,397) 214,500 21,985 |
Fair Value Of Derivatives | As of June 30, 2019 Derivative Assets Derivative Liabilities Balance Sheet Balance Sheet Classification Fair Value Classification Fair Value Commodity contracts Current assets - Current liabilities 150,703 Commodity contracts Noncurrent assets 365,542 Noncurrent liabilities - Total commodity contracts 365,542 150,703 As of June 30, 2018 Derivative Assets Derivative Liabilities Balance Sheet Balance Sheet Classification Fair Value Classification Fair Value Commodity contracts Current assets - Current liabilities 1,210,795 Commodity contracts Noncurrent assets - Noncurrent liabilities - Total commodity contracts - 1,210,795 |
Componenets Of Derivative (Gain) Loss | For the Years Ended June 30, 2019 2018 Unrealized gain (loss) on derivatives 1,425,634 (946,438) Realized gain (loss) on derivatives (968,418) (1,775,728) Total gain (loss) on derivatives 457,216 (2,722,166) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Fair Value Measurements [Abstract] | |
Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis | Fair Value at June 30, 2019 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash, restricted cash and cash equivalents $ 2,774,487 $ - $ - $ - $ 2,774,487 Derivative Instruments - 16,889 - (16,889) - Non Current Assets: Derivative Instruments - 377,845 - (12,303) 365,542 Current Liabilities Derivative Instruments - (167,592) - 16,889 (150,703) Non Current Liabilities: Derivative Instruments (12,303) - 12,303 - Fair Value at June 30, 2018 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 1,376,676 $ - $ - $ - $ 1,376,676 Derivative Instruments - 4,218 - (4,218) - Non Current Assets: Derivative Instruments - - - - - Current Liabilities Derivative Instruments - 1,215,013 - (4,218) 1,210,795 Non Current Liabilities: Derivative Instruments - - - |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Asset Retirement Obligations [Abstract] | |
Summary Of Activities For Asset Retirement Obligations | 2019 2018 Asset retirement obligations at beginning of period $ 3,344,112 $ 3,240,007 Liabilities incurred or acquired - - Liabilities settled (295,282) (73,667) Disposition of properties - (73,011) Accretion expense 561,950 250,783 Asset retirement obligations at end of period 3,610,780 3,344,112 Long-term asset retirement obligations $ 3,610,780 $ 3,344,112 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Income Taxes [Abstract] | |
Schedule Of Components Of Income Tax Provision (Benefit) | June 30 2019 2018 Current: Federal $ - $ - State 200 - 200 - Deferred: Federal (48,144) (732,056) State - - Total income tax benefit $ (47,944) $ (732,056) |
Schedule Of Effective Income tax Rate Reconciliation | June 30 2019 2018 Income tax expense (benefit) at federal statutory rate $ (1,979,000) $ (1,956,277) Effect of Permanent Differences and Other-US 121,000 115,616 State Taxes, Net of Federal Benefit (600,000) (123,694) Change in Valuation Allowance 1,692,000 (10,104,596) Change in Tax Rate 342,000 11,207,430 US income taxed at a different rate 432,000 116,777 Other (55,944) 12,688 Total income tax benefit $ (47,944) $ (732,056) |
Schedule Of Components Of Deferred Tax Assets and (Liabilities) | June 30 2019 2018 Deferred income tax assets: Net operating losses $ 26,450,000 $ 23,674,591 Asset retirement obligation 807,000 737,876 Abandonment limitation - 544,869 Debt issuance costs 312,000 - AMT Credit 780,000 780,443 Provision for Annual Leave 50,000 51,837 Allowance For Doubtful Accounts 59,000 17,558 Share based comp 459,000 500,845 Hedge Liability - 283,458 Gross deferred tax assets $ 28,917,000 $ 26,591,477 Deferred income tax liabilities: Oil and gas property (2,085,000) (1,908,395) Hedge Liability (51,000) - Gross deferred tax liabilities $ (2,136,000) $ (1,908,395) Net deferred income tax assets (liabilities) 26,781,000 24,683,082 Valuation allowance (26,001,000) (23,951,026) Noncurrent deferred tax asset $ 780,000 $ 732,056 |
Common Stock (Tables)
Common Stock (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Common Stock [Abstract] | |
Contributed Equity | June 30, 2019 2018 328,300,044 ordinary fully paid shares including shares to be issued $ 106,743,167 $ 106,743,167 |
Movements In Contributed Equity For The Year | Movements in contributed equity for the year 2019 2018 No. of shares $ No. of shares $ Opening balance 328,300,044 106,743,167 328,300,044 106,390,864 Capital raising (i) - - - - Shares issued upon exercise of options (ii) - - - - Share based compensation - - - 352,303 Transaction costs incurred - - - - Shares on issue at balance date 328,300,044 106,743,167 328,300,044 106,743,167 |
Credit Facility (Tables)
Credit Facility (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Credit Facility [Abstract] | |
Schedule of Credit Facilities | June 30, 2019 2018 Credit facility at beginning of period $ 23,867,557 $ 23,419,749 Cash advanced under Credit Agreement 33,561,707 450,000 Repayments (23,929,264) (2,192) Credit facility at end of period $ 33,500,000 $ 23,867,557 Funds available for drawdown under the facility - - |
Share-Based Payments (Tables)
Share-Based Payments (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Share-Based Payments [Abstract] | |
Summary Of Stock Option Activity | 2019 2018 Weighted Aggregate Weighted Average Intrinsic Average Exercise Price Value of Exercise Price Number A$ A$ Number A$ Outstanding, start of period 314,500,000 0.057 - 411,033,246 0.0118 Granted - - - - - Exercised - - - - - Cancelled/expired - - - (96,533,246) 0.0380 Outstanding, end of period 314,500,000 0.057 - 314,500,000 0.0570 Exercisable, end of period 314,500,000 0.057 - 314,500,000 0.0570 (1) The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date. If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option. |
Schedule Of Additional Information Related To Options Outstanding | Options/Warrants Outstanding and Exercisable Weighted Average Range of Remaining Exercise Number Contractual Prices (A$) Outstanding Life - years $0.070 48,000,000 7.42 $0.055 266,500,000 7.42 314,500,000 |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Commitments [Abstract] | |
Contractual Obligations | Total 2020 2021 2022 2023 Thereafter Leases 219,643 103,616 107,080 8,947 - - |
Supplemental Information On O_2
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Tables) | 12 Months Ended |
Jun. 30, 2019 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | |
Summary Of Costs Incurred For Oil And Natural Gas Exploration, Development And Acquisition | Year ended June 30, 2019 2018 Development 1,462,483 13,272 Undeveloped capitalized acreage - - Total costs incurred $ 1,462,483 $ 13,272 |
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities | Year ended June 30, 2019 Year ended June 30, 2018 Oil Gas Total Oil Gas Total Mbbls MMcf MBOE Mbbls MMcf MBOE Beginning of year 3,515 1,292 3,732 5,359 3,565 5,954 Revisions of previous quantity estimates * (361) (342) (419) (1,657) (2,258) (2,033) Extensions and discoveries - - - - - - Sale of reserves in place - - - - - - Acquisitions - - - - - - Production (224) (35) (230) (187) (15) (189) End of year 2,930 915 3,083 3,515 1,292 3,732 Proved developed producing reserves 2,930 915 3,083 2,663 623 2,768 Proved developed non producing * - - - 544 418 614 Proved undeveloped reserves * - - - 308 251 350 Total proved reserves 2,930 915 3,083 3,515 1,292 3,732 * Given the Company’s current financial condition there is no assurance that it will have the necessary financial resources available to meet the investment and operating criteria , as defined under SEC regulation, to execute the development plan necessary to include PDNP and PUD reserves in the Company’s reserve report . |
Schedule Of Estimated Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Reserves | As at June 30, 2019 2018 Future cash inflows $ 166,709 $ 187,249 Future production costs (85,626) (99,620) Future development costs - (1,642) Future income taxes - - Future net cashflows 81,083 85,987 10 % discount (33,513) (38,325) Standardized measure of discounted future net cash flows relating to proved reserves $ 47,570 $ 47,662 Standardized Measure PV10 Future cash inflows $ 166,709 $ 97,805 Future production costs (85,626) (50,235) Future development costs - - Future income taxes - - Future net cash flows 81,083 47,570 10% annual discount (33,513) - Discounted future net cash flows $ 47,570 $ 47,570 |
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Fiscal Year Ended June 30 2019 2018 Beginning of year $ 47,662 $ 65,262 Sales of oil and gas, net of production costs and taxes (321) (3,902) Extensions and discoveries, net of costs 396 - Purchases of reserves in place - - Sales of reserves in place - - Changes in prices and production costs 3,476 2,822 Revisions of previous quantity estimates and other (8,884) (10,088) Previously estimated development costs incurred - - Changes in estimated future development costs 502 (11,625) Accretion of discount 4,766 - Net changes in income taxes - 6,526 Changes in timing and other (27) (1,333) Balance at end of year $ 47,570 $ 47,662 |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | |
Jun. 30, 2019USD ($)segment | Jun. 30, 2018USD ($) | |
Significant Accounting Policies [Line Items] | ||
Net loss | $ (7,148,031) | $ (6,038,866) |
Cash outflows from operating activities | (5,367,466) | 742,289 |
Current liabilities | 43,346,509 | 34,950,504 |
Capital Reserve Amount | 1,000,000 | |
Debt Service Reserve | 1,100,000 | |
Current assets | 4,756,610 | 3,642,185 |
Current portion of credit facility | $ 33,500,000 | 23,867,558 |
Number of operating segments | segment | 1 | |
Depreciation Depletion And Amortization | $ 1,824,014 | 1,237,989 |
Provision for bad debt expense | 175,000 | 75,000 |
Exploratory costs charged to expense | 200,000 | |
Impairment of oil and natural gas properties | $ 0 | |
Minimum percentage of likelihood tax benefits recognized from uncertain tax position, reasonably possible upon settlement | 50.00% | |
Operating Leases, Future Minimum Payments Due | $ 219,643 | |
Other Property And Equipment [Member] | ||
Significant Accounting Policies [Line Items] | ||
Depreciation Depletion And Amortization | $ 30,000,000,000 | $ 85,000,000,000 |
Other Property And Equipment [Member] | Minimum [Member] | ||
Significant Accounting Policies [Line Items] | ||
Property, Plant and Equipment, Useful Life | 3 years | |
Other Property And Equipment [Member] | Maximum [Member] | ||
Significant Accounting Policies [Line Items] | ||
Property, Plant and Equipment, Useful Life | 25 years |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Less provision for doubtful debts | $ (250,000) | $ (75,000) |
Total accounts receivable | 1,982,123 | 1,908,879 |
Oil And Natural Gas Sales Related Receivable [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable | 1,538,451 | 1,159,905 |
Cost Recovery From JV Partner Receivable [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Accounts receivable | 650,885 | 768,281 |
Other Receivable [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Total accounts receivable | $ 42,787 | $ 55,693 |
Summary Of Significant Accoun_6
Summary Of Significant Accounting Policies (Schedule Of Oil And Gas Properties And Equipment) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Summary Of Significant Accounting Policies [Abstract] | ||
Proved properties, net of impairment | $ 39,666,294 | $ 38,110,237 |
Work in progress | 40,319 | 8,271 |
Less accumulated depreciation, depletion and impairment | (9,491,784) | (7,697,667) |
Total oil and gas properties and equipment | 30,214,829 | 30,420,841 |
Unproved acreage |
Summary Of Significant Accoun_7
Summary Of Significant Accounting Policies (Schedule Of Other Property And Equipment) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Summary Of Significant Accounting Policies [Abstract] | ||
Furniture, fittings and equipment | $ 930,173 | $ 1,017,879 |
Less accumulated depreciation | (755,241) | (775,057) |
Total other property and equipment | $ 174,931 | $ 242,822 |
Summary Of Significant Accoun_8
Summary Of Significant Accounting Policies (Schedule Of Earnings Per Share, Basic And Diluted) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Summary Of Significant Accounting Policies [Abstract] | ||
Net loss | $ (7,148,031) | $ (6,038,866) |
Basic and diluted weighted average common shares outstanding | 328,300,044 | 328,300,044 |
Basic and diluted loss per common share - cents per share | $ (0.02) | $ (0.02) |
Revenue From Contracts With C_3
Revenue From Contracts With Customers (Narrative) (Details) - USD ($) $ in Millions | Jun. 30, 2019 | Jun. 30, 2018 |
Revenue From Contracts With Customers [Abstract] | ||
Accounts receivable | $ 1.5 | $ 1 |
Revenue From Contracts With C_4
Revenue From Contracts With Customers (Disaggregation of Revenue) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Disaggregation of Revenue [Line Items] | ||
Oil and gas income | $ 12,662,865 | $ 10,058,719 |
Oil [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil and gas income | 12,391,536 | 9,931,065 |
Natural Gas [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil and gas income | 257,895 | 118,783 |
Other Liquids [Member] | ||
Disaggregation of Revenue [Line Items] | ||
Oil and gas income | $ 13,434 | $ 8,871 |
Hedging And Derivative Financ_3
Hedging And Derivative Financial Instruments (Narrative) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Derivative [Line Items] | ||
Assets | $ 365,542 | |
Liabilities | 150,703 | $ 1,210,795 |
Commodity Contract [Member] | ||
Derivative [Line Items] | ||
Assets | $ 200,000 | |
Liabilities | $ 1,200,000 |
Hedging And Derivative Financ_4
Hedging And Derivative Financial Instruments (Schedule Of Open Derivative Contracts) (Details) | 12 Months Ended |
Jun. 30, 2019USD ($)$ / bblbbl | |
W&T Offshore, Inc. [Member] | |
Derivative [Line Items] | |
Volumes | bbl | 693,000 |
Estimated Fair Value | $ | $ 192,854 |
W&T Offshore, Inc. [Member] | Derivative Contract One [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2019 |
Volumes | bbl | 109,000 |
Estimated Fair Value | $ | $ (118,762) |
W&T Offshore, Inc. [Member] | Derivative Contract Two [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2020 |
Volumes | bbl | 200,000 |
Estimated Fair Value | $ | $ 38,418 |
W&T Offshore, Inc. [Member] | Derivative Contract Three [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2021 |
Volumes | bbl | 182,000 |
Estimated Fair Value | $ | $ 118,142 |
W&T Offshore, Inc. [Member] | Derivative Contract Five [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2022 |
Volumes | bbl | 163,000 |
Estimated Fair Value | $ | $ 134,254 |
W&T Offshore, Inc. [Member] | Derivative Contract Six [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2023 |
Volumes | bbl | 39,000 |
Estimated Fair Value | $ | $ 20,802 |
Henry Hub [Member] | |
Derivative [Line Items] | |
Volumes | bbl | 214,500 |
Estimated Fair Value | $ | $ 21,985 |
Henry Hub [Member] | Derivative Contract Seven [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2019 |
Volumes | bbl | 30,000 |
Floor price | 2.60 |
Ceiling price | 2.80 |
Estimated Fair Value | $ | $ 6,875 |
Henry Hub [Member] | Derivative Contract Eight [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2020 |
Volumes | bbl | 63,900 |
Floor price | 2.60 |
Ceiling price | 2.80 |
Estimated Fair Value | $ | $ 7,709 |
Henry Hub [Member] | Derivative Contract Nine [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2021 |
Volumes | bbl | 57,600 |
Floor price | 2.60 |
Ceiling price | 2.80 |
Estimated Fair Value | $ | $ 5,122 |
Henry Hub [Member] | Derivative Contract Ten [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2022 |
Volumes | bbl | 51,300 |
Floor price | 2.60 |
Ceiling price | 2.80 |
Estimated Fair Value | $ | $ 3,676 |
Henry Hub [Member] | Derivative Contract Eleven [Member] | |
Derivative [Line Items] | |
Year | Dec. 31, 2023 |
Volumes | bbl | 11,700 |
Floor price | 2.60 |
Ceiling price | 2.80 |
Estimated Fair Value | $ | $ (1,397) |
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract One [Member] | |
Derivative [Line Items] | |
Swap | 55.75 |
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Two [Member] | |
Derivative [Line Items] | |
Swap | 55.39 |
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Three [Member] | |
Derivative [Line Items] | |
Swap | 54.03 |
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Five [Member] | |
Derivative [Line Items] | |
Swap | 53.15 |
Minimum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Six [Member] | |
Derivative [Line Items] | |
Swap | 53.46 |
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract One [Member] | |
Derivative [Line Items] | |
Swap | 58.10 |
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Two [Member] | |
Derivative [Line Items] | |
Swap | 57.05 |
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Three [Member] | |
Derivative [Line Items] | |
Swap | 55.70 |
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Five [Member] | |
Derivative [Line Items] | |
Swap | 55.70 |
Maximum [Member] | W&T Offshore, Inc. [Member] | Derivative Contract Six [Member] | |
Derivative [Line Items] | |
Swap | 55.70 |
Hedging And Derivative Financ_5
Hedging And Derivative Financial Instruments (Fair Value Of Derivatives) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Hedging And Derivative Financial Instruments [Abstract] | ||
Noncurrent assets | $ 365,542 | |
Assets | 365,542 | |
Current liabilities | 150,703 | $ 1,210,795 |
Liabilities | $ 150,703 | $ 1,210,795 |
Hedging And Derivative Financ_6
Hedging And Derivative Financial Instruments (Componenets Of Derivative (Gain) Loss) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Hedging And Derivative Financial Instruments [Abstract] | ||
Unrealized gain (loss) on derivatives | $ 1,425,634 | $ (946,438) |
Realized gain (loss) on derivatives | (968,418) | (1,775,728) |
Total gain (loss) on derivatives | $ 457,216 | $ (2,722,166) |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | $ 2,774,487 | $ 1,376,676 | |
Non Current Assets, Derivative Instruments | 365,542 | ||
Current Liabilities, Derivative Instruments | 150,703 | 1,210,795 | |
Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | 2,774,487 | 1,376,676 | |
Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | |||
Current Assets, Derivative Instruments | 16,889 | 4,218 | |
Non Current Assets, Derivative Instruments | 377,845 | ||
Current Liabilities, Derivative Instruments | 167,592 | 1,215,013 | |
Non Current Liabilities, Derivative Instruments | (12,303) | ||
Level 3 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | |||
Current Assets, Derivative Instruments | |||
Non Current Assets, Derivative Instruments | |||
Current Liabilities, Derivative Instruments | |||
Non Current Liabilities, Derivative Instruments | |||
Netting [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Current Assets, Derivative Instruments | [1] | (16,889) | (4,218) |
Non Current Assets, Derivative Instruments | [1] | (12,303) | |
Current Liabilities, Derivative Instruments | [1] | (16,889) | $ (4,218) |
Non Current Liabilities, Derivative Instruments | [1] | $ 12,303 | |
[1] | Netting In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of loss is somewhat mitigated. |
Asset Retirement Obligations (N
Asset Retirement Obligations (Narrative) (Details) | 12 Months Ended |
Jun. 30, 2019 | |
Minimum [Member] | |
Asset Retirement Obligations, Discount Rate | 4.00% |
Maximum [Member] | |
Asset Retirement Obligations, Discount Rate | 13.00% |
Asset Retirement Obligations (S
Asset Retirement Obligations (Summary Of Activities Of Asset Retirement Obligations) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Asset Retirement Obligations [Abstract] | ||
Asset retirement obligations at beginning of period | $ 3,344,112 | $ 3,240,007 |
Liabilities incurred or acquired | ||
Liabilities settled | (295,282) | (73,667) |
Disposition of properties | (73,011) | |
Accretion expense | 561,950 | 250,783 |
Asset retirement obligations at end of period | 3,610,780 | 3,344,112 |
Long-term asset retirement obligations | $ 3,610,780 | $ 3,344,112 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Income Taxes [Line Items] | ||
Tax expense (benefit) | $ 200 | |
Tax Year 2011 [Member] | ||
Income Taxes [Line Items] | ||
Net operating tax losses | $ 9,200,000 | |
Australian Taxation Office [Member] | ||
Income Taxes [Line Items] | ||
Federal statutory rate | 30.00% | |
Tax losses carried forward | $ 17,400,000 | |
Benefit of tax losses carried forward | 4,800,000 | |
Internal Revenue Service (IRS) [Member] | ||
Income Taxes [Line Items] | ||
Net operating tax losses | 94,100,000 | |
Limitation per year | $ 403,194 | |
Internal Revenue Service (IRS) [Member] | Tax Year 2011 [Member] | ||
Income Taxes [Line Items] | ||
Net operating losses, expiration year | Jun. 30, 2025 | |
Amount not utilized | $ 4,000,000 | |
Minimum [Member] | Internal Revenue Service (IRS) [Member] | ||
Income Taxes [Line Items] | ||
Net operating losses, expiration year | Jan. 1, 2020 | |
Minimum [Member] | State and Local Jurisdiction [Member] | ||
Income Taxes [Line Items] | ||
Net operating losses, expiration year | Dec. 31, 2020 | |
Maximum [Member] | Internal Revenue Service (IRS) [Member] | ||
Income Taxes [Line Items] | ||
Net operating losses, expiration year | Dec. 31, 2038 | |
Maximum [Member] | State and Local Jurisdiction [Member] | ||
Income Taxes [Line Items] | ||
Net operating losses, expiration year | Dec. 31, 2039 |
Income Taxes (Schedule Of Compo
Income Taxes (Schedule Of Components Of Income Tax Provision (Benefit)) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Income Taxes [Abstract] | ||
Current State | $ 200 | |
Current | 200 | |
Deferred Federal | (48,144) | $ (732,056) |
Effective income tax rate | $ (47,944) | $ (732,056) |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income tax Rate Reconciliation) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Income Taxes [Abstract] | ||
Income tax expense (benefit) at federal statutory rate | $ (1,979,000) | $ (1,956,277) |
Effect of permanent differences and other - US | 121,000 | 115,616 |
State Taxes, Net of Federal Benefit | (600,000) | (123,694) |
Change in Valuation Allowance | 1,692,000 | (10,104,596) |
Change in tax rate | 342,000 | 11,207,430 |
US income taxed at a different rate | 432,000 | 116,777 |
Other | (55,944) | 12,688 |
Effective income tax rate | $ (47,944) | $ (732,056) |
Income Taxes (Schedule Of Com_2
Income Taxes (Schedule Of Components Of Deferred Tax Assets and (Liabilities)) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Income Taxes [Abstract] | ||
Net operating losses | $ 26,450,000 | $ 23,674,591 |
Asset retirement obligation | 807,000 | 737,876 |
Abandonment limitation | 544,869 | |
Debt issuance costs | 312,000 | |
AMT Credit | 780,000 | 780,443 |
Provision for Annual Leave | 50,000 | 51,837 |
Allowance for doubtful debts | 59,000 | 17,558 |
Share based compensation | 459,000 | 500,845 |
Hedge Liability | 283,458 | |
Gross deferred tax assets | 28,917,000 | 26,591,477 |
Oil and gas property | (2,085,000) | (1,908,395) |
Hedge Liability | (51,000) | |
Gross deferred tax liabilities | (2,136,000) | (1,908,395) |
Net deferred income tax assets (liabilities) | 26,781,000 | 24,683,082 |
Valuation allowance | (26,001,000) | (23,951,026) |
Noncurrent deferred tax asset | $ 780,000 | $ 732,056 |
Common Stock (Contributed Equit
Common Stock (Contributed Equity) (Details) - USD ($) | Jun. 30, 2019 | Jun. 30, 2018 |
Common Stock [Abstract] | ||
328,300,044 ordinary fully paid shares including shares to be issued | $ 106,743,167 | $ 106,743,167 |
Common stock outstanding and to be issued | 328,300,044 |
Common Stock (Movements In Cont
Common Stock (Movements In Contributed Equity For The Year) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Shares issued upon exercise of options, shares | 0 | |
Stock based compensation | $ 352,303 | |
Issued Capital [Member] | ||
Beginning Balance, shares | 328,300,044 | 328,300,044 |
Opening balance, value | $ 106,743,167 | $ 106,390,864 |
Capital raising, shares | ||
Capital raising | ||
Shares issued upon exercise of options, shares | 0 | |
Shares issued upon exercise of options, value | ||
Share based payment, shares | ||
Stock based compensation | $ 352,303 | |
Transaction costs incurred, value | ||
Ending Balance, shares | 328,300,044 | 328,300,044 |
Shares on issue at balance date, value | $ 106,743,167 | $ 106,743,167 |
Credit Facility (Narrative) (De
Credit Facility (Narrative) (Details) | Apr. 09, 2019USD ($) | Jun. 30, 2019USD ($) |
Line of Credit Facility [Line Items] | ||
Payments for costs associated with borrowings | $ 1,390,565 | |
Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 33,500,000 | |
Payments for costs associated with borrowings | 1,400,000 | $ 1,400,000 |
Term | 5 years | |
Line of credit facility, expiration date | Apr. 9, 2024 | |
Debt instrument, basis spread on variable rate | 10.50% | |
Previous Credit Facility [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility, maximum borrowing capacity | $ 23,900,000 | |
Minimum [Member] | Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt instrument, interest rate at period end | 5.00% | |
Current ratio | 1 | |
Maximum [Member] | Credit Agreement [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt instrument, interest rate at period end | 13.00% | |
Maximum [Member] | Credit Agreement [Member] | Date [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt to EBITDAX | 4.75 | |
Maximum [Member] | Credit Agreement [Member] | Date B [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt to EBITDAX | 4 | |
Maximum [Member] | Credit Agreement [Member] | Date C [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt to EBITDAX | 3.50 | |
Maximum [Member] | Credit Agreement [Member] | Date D [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt to EBITDAX | 3 | |
Maximum [Member] | Credit Agreement [Member] | Date E [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio | 2 | |
Maximum [Member] | Credit Agreement [Member] | Date F [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio | 2.50 | |
Maximum [Member] | Credit Agreement [Member] | Date G [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio (PDP) | 1.10 | |
Maximum [Member] | Credit Agreement [Member] | Date H [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio (PDP) | 1.15 | |
Maximum [Member] | Credit Agreement [Member] | Date I [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio (PDP) | 1.25 | |
Maximum [Member] | Credit Agreement [Member] | Date J [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio (PDP) | 1.50 | |
Maximum [Member] | Credit Agreement [Member] | Date K [Member] | ||
Line of Credit Facility [Line Items] | ||
Asset Coverage Ratio (PDP) | 1.75 | |
Maximum [Member] | Credit Agreement [Member] | Date L [Member] | ||
Line of Credit Facility [Line Items] | ||
Fixed Charge Coverage Ratio | 1.35 | |
Maximum [Member] | Credit Agreement [Member] | Date M [Member] | ||
Line of Credit Facility [Line Items] | ||
Fixed Charge Coverage Ratio | 1.40 | |
Maximum [Member] | Credit Agreement [Member] | Date N [Member] | ||
Line of Credit Facility [Line Items] | ||
Capital Expenditures | 10.00% | |
Maximum [Member] | Credit Agreement [Member] | Date O [Member] | ||
Line of Credit Facility [Line Items] | ||
Capital Expenditures | 10.00% |
Credit Facility (Schedule of Cr
Credit Facility (Schedule of Credit Facilities) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2017 | |
Credit Facility [Abstract] | ||
Credit facility at beginning of period | $ 23,867,557 | $ 23,419,749 |
Cash advanced under facility | 33,561,707 | 450,000 |
Repayments | (23,929,264) | (2,192) |
Credit facility at end of period | 33,500,000 | 23,867,557 |
Funds available for drawdown under the facility |
Share-Based Payments (Narrative
Share-Based Payments (Narrative) (Details) - shares | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Share-Based Payments [Abstract] | ||
Options exercised | 0 |
Share-Based Payments (Summary O
Share-Based Payments (Summary Of Stock Option Activity) (Details) | 12 Months Ended | |||||
Jun. 30, 2019AUD ($)$ / sharesshares | Jun. 30, 2019AUD ($)$ / sharesshares | Jun. 30, 2018$ / sharesshares | Jun. 30, 2018$ / sharesshares | |||
Share-Based Payments [Abstract] | ||||||
Outstanding, start of period | shares | 314,500,000 | 314,500,000 | 411,033,246 | 411,033,246 | ||
Granted | shares | ||||||
Exercised | shares | 0 | 0 | ||||
Cancelled/expired | shares | (96,533,246) | (96,533,246) | ||||
Outstanding, end of period | shares | 314,500,000 | 314,500,000 | 314,500,000 | 314,500,000 | ||
Exercisable, end of period | shares | 314,500,000 | 314,500,000 | 314,500,000 | 314,500,000 | ||
Weighted average exercise price - cents (AUD), outstanding, start of period | $ / shares | $ 0.0570 | $ 0.0118 | ||||
Weighted average exercise price - cents (AUD), granted | $ / shares | ||||||
Weighted average exercise price - cents (AUD), exercised | $ / shares | ||||||
Weighted average exercise price - cents (AUD), cancelled/expired | $ / shares | 0.0380 | |||||
Weighted average exercise price - cents (AUD), outstanding, end of period | $ / shares | 0.0570 | 0.0570 | ||||
Weighted average exercise price - cents (AUD), exercisable, end of period | $ / shares | $ 0.0570 | $ 0.0570 | ||||
Aggregate intrinsic value of options - cents (AUD) | $ | [1] | [1] | ||||
[1] | The intrinsic value of a stock option is the amount by which the market value exceeds the exercise price at the Balance Date. If the exercise price of the stock option is greater than the market price then the intrinsic value is zero, because the holder would not exercise the option. |
Share-Based Payments (Schedule
Share-Based Payments (Schedule Of Additional Information Related To Options Outstanding) (Details) | 12 Months Ended |
Jun. 30, 2019$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Number Outstanding | 314,500,000 |
$0.070 [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Range of Exercise Prices, Max | $ / shares | $ 0.070 |
Number Outstanding | 48,000,000 |
Weighted Average Remaining Contractual Life - years | 7 years 5 months 1 day |
$0.055 [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Range of Exercise Prices, Min | $ / shares | $ 0.055 |
Number Outstanding | 266,500,000 |
Weighted Average Remaining Contractual Life - years | 7 years 5 months 1 day |
Commitments (Details)
Commitments (Details) | Jun. 30, 2019USD ($) |
Commitments [Abstract] | |
Operating leases, Total | $ 219,643 |
Operating leases, 2020 | 103,616 |
Operating leases, 2021 | 107,080 |
Operating leases, 2022 | 8,947 |
Operating leases, 2023 |
Supplemental Information On O_3
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Summary Of Costs Incurred For Oil And Natural Gas Exploration, Development And Acquisition) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | ||
Development costs | $ 1,462,483 | $ 13,272 |
Total costs incurred | $ 1,462,483 | $ 13,272 |
Supplemental Information On O_4
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities) (Details) | 12 Months Ended | |
Jun. 30, 2019MBoeMBblsMMcf | Jun. 30, 2018MBoeMBblsMMcf | |
Reserve Quantities [Line Items] | ||
Proved Developed Reserves ProductionBOE | MBoe | (230) | (189) |
Beginning of year (BOE) | MBoe | 3,732 | 5,954 |
Revisions of previous quantity estimates (BOE) | MBoe | (419) | (2,033) |
End of year (BOE) | MBoe | 3,083 | 3,732 |
Proved developed producing reserves (BOE) | MBoe | 3,083 | 2,768 |
Proved undeveloped reserves (BOE) | MBoe | 350 | |
Proved Developed Non Producing (BOE) | MBoe | 614 | |
Proved reserves (BOE) | MBoe | 3,083 | 3,732 |
Oil [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of year (Volume) | MBbls | 3,515 | 5,359 |
Revisions of previous quantity estimates (Volume) | MBbls | (361) | (1,657) |
Production (Volume) | MBbls | (224) | (187) |
End of year (Volume) | MBbls | 2,930 | 3,515 |
Proved developed producing reserves (Volume) | MBbls | 2,930 | 2,663 |
Proved Developed Non Producing (Volume) | MBbls | 544 | |
Proved undeveloped reserves (Volume) | MBbls | 308 | |
Proved reserves (Volume) | MBbls | 2,930 | 3,515 |
Natural Gas [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of year (Volume) | MMcf | 1,292 | 3,565 |
Revisions of previous quantity estimates (Volume) | MMcf | (342) | (2,258) |
Production (Volume) | MMcf | (35) | (15) |
End of year (Volume) | MMcf | 915 | 1,292 |
Proved developed producing reserves (Volume) | MMcf | 915 | 623 |
Proved Developed Non Producing (Volume) | MMcf | 418 | |
Proved undeveloped reserves (Volume) | MMcf | 251 | |
Proved reserves (Volume) | MMcf | 915 | 1,292 |
Supplemental Information On O_5
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Estimated Standard Measure Of Discounted Future Net CF Relating To Proved Reserves) (Details) - USD ($) $ in Thousands | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2017 |
Standardized Measure [Abstract] | |||
Future cash inflows | $ 166,709 | $ 187,249 | |
Future production costs | (85,626) | (99,620) | |
Future development costs | (1,642) | ||
Future net cashflows | 81,083 | 85,987 | |
10% discount | (33,513) | (38,325) | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | 47,570 | $ 47,662 | $ 65,262 |
PV10 [Abstract] | |||
Future cash inflows | 97,805 | ||
Future production costs | (50,235) | ||
Future net cashflows | 47,570 | ||
Discounted future net cash flows | $ 47,570 |
Supplemental Information On O_6
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Jun. 30, 2019 | Jun. 30, 2018 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | ||
Beginning of year | $ 47,662 | $ 65,262 |
Sales of oil and gas produced during the period, net of production costs | (321) | (3,902) |
Extensions, discoveries and improved recovery | 396 | |
Changes in prices and production costs | 3,476 | 2,822 |
Revisions of previous quantity estimates and other | (8,884) | (10,088) |
Changes in estimates of future development costs | 502 | (11,625) |
Accretion of discount | 4,766 | |
Net changes in income taxes | 6,526 | |
Changes in timing and other | (27) | (1,333) |
Balance at end of year | $ 47,570 | $ 47,662 |