Document And Entity Information
Document And Entity Information - USD ($) $ in Thousands | 12 Months Ended | ||
Jun. 30, 2018 | Sep. 28, 2018 | Dec. 29, 2017 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Jun. 30, 2018 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | FY | ||
Trading Symbol | SSN | ||
Entity Registrant Name | Samson Oil & Gas LTD | ||
Entity Central Index Key | 1,404,079 | ||
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 | Smaller Reporting Company | ||
Entity Common Stock, Shares Outstanding | 3,283,000,444 | ||
Entity Public Float | $ 2,100 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 1,376,676 | $ 628,778 |
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively | 1,759,461 | 1,550,438 |
Energy Related Inventory, Crude Oil and Natural Gas Liquids | 219,288 | 219,288 |
Prepayments | 137,342 | 54,519 |
Assets Held-for-sale, Not Part of Disposal Group, Current | 28,675,890 | |
Total current assets | 32,168,657 | 2,453,023 |
PROPERTY, PLANT AND EQUIPMENT, AT COST | ||
Oil and gas properties, successful efforts method of accounting, less accumulated depreciation, depletion and impairment of $44,273,976 and $21,219,361 at June 30, 2015 and June 30, 2014, respectively | 1,744,951 | 1,814,772 |
Oil and gas properties held for sale | 29,682,501 | |
Other property and equipment, net of accumulated depreciation and amortization of $553,428 and $421,443 at June 30, 2015 and June 30, 2014, respectively | 242,822 | 296,077 |
Net property, plant and equipment | 1,987,773 | 31,793,350 |
OTHER ASSETS | ||
Undeveloped capitalized acreage | 271,078 | |
Fair value of derivative instruments | 99,603 | |
Malpractice Loss Contingency, Letters of Credit and Surety Bonds | 450,000 | 450,000 |
Deferred tax asset | 732,056 | |
Other | 134,644 | 291,181 |
TOTAL ASSETS | 35,473,130 | 35,358,235 |
CURRENT LIABILITIES | ||
Accounts payable | 8,383,570 | 4,287,955 |
Accrued liabilities | 1,088,338 | 821,319 |
Provision for annual leave | 250,826 | 249,060 |
Fair value of derivative instruments | 1,210,795 | 363,960 |
Asset retirement obligations related to assets held for sale | 2,509,981 | 2,475,427 |
Short term repayment of long term debt | 23,867,557 | 23,419,749 |
Total current liabilities | 37,311,067 | 31,617,470 |
Asset retirement obligations | 834,131 | 680,809 |
Total liabilities | 38,145,198 | 32,298,279 |
Commitments and Contingencies | ||
STOCKHOLDERS' EQUITY - nil par value | ||
Common stock, 2,837,756,933 (equivalent to 141,887,847 ADRs) and 2,229,165,163 (equivalent to 111,458,258 ADRs) shares issued and outstanding at June 30, 2014 and 2013, respectively) | 106,743,167 | 106,390,864 |
Other comprehensive income | 846,556 | 892,017 |
Retained earnings (accumulated deficit) | (110,261,791) | (104,222,925) |
Total stockholders' equity | (2,672,068) | 3,059,956 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 35,473,130 | $ 35,358,235 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2014 | Jun. 30, 2013 |
Consolidated Balance Sheets [Abstract] | ||||
Accounts receivable, allowance for doubtful accounts | $ 75,000 | |||
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion Amortization and Impairment | 12,606,419 | $ 12,440,389 | ||
Other property and equipment, accumulated depreciation and amortization | $ 775,057 | $ 693,945 | ||
Common stock, par value | ||||
Common stock, shares issued | 3,282,000,444 | 3,282,000,444 | ||
Common stock, shares outstanding | 3,282,000,444 | 3,282,000,444 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
REVENUES AND OTHER INCOME: | ||
Interest income | $ 229 | $ 411 |
Gain on derivative instruments | 1,297,472 | |
Gain on sale of exploration acreage | 178,407 | 2,250,070 |
Other | 80,893 | 66,707 |
TOTAL REVENUE AND OTHER INCOME | 538,811 | 6,168,229 |
EXPENSES: | ||
Lease operating expense | (460,114) | (2,209,583) |
Depletion, depreciation and amortization | (166,030) | (218,635) |
Impairment of oil and natural gas properties | (244,480) | |
Exploration and evaluation expenditure | (325,304) | (78,391) |
Accretion of asset retirement obligations | (34,554) | (52,801) |
General and administrative | (4,141,399) | (5,034,746) |
Abandonment Expense | (128,862) | (3,055) |
Loss on derivative instruments | (2,722,166) | |
Borrowing costs | (440,434) | (219,810) |
Provision for doubtful debts | 75,000 | |
TOTAL EXPENSES | (8,053,429) | (7,841,691) |
Loss before income tax | (7,514,618) | (1,673,462) |
Income tax (provision)/benefit | 732,056 | |
Net loss from continuing operations | (6,782,562) | (1,673,462) |
Income/(loss) from discontinued operations | 743,696 | (1,094,034) |
Net loss from operations | (6,038,866) | (2,767,496) |
OTHER COMPREHENSIVE LOSS | ||
Foreign currency translation | (45,461) | (35,701) |
Total comprehensive loss for the period | $ (6,084,327) | $ (2,803,197) |
Net earnings per common share from continuing operations: | ||
Basic loss per common share - cents per share | $ (0.21) | $ (0.05) |
Diluted earnings per common share - cents per share | (0.21) | (0.05) |
Net earnings per common share from discontinued operations: | ||
Basic - cents per share | 0.02 | (0.03) |
Diluted - cents per share | 0.02 | (0.03) |
Net gain(loss) from operations per common share: | ||
Basic - cents per share | (0.19) | (0.08) |
Diluted - cents per share | $ (0.19) | $ (0.08) |
Weighted average common shares outstanding: | ||
Basic | 3,283,000,444 | 3,257,194,847 |
Diluted | 3,283,000,444 | 3,257,194,847 |
Oil [Member] | ||
REVENUES AND OTHER INCOME: | ||
TOTAL REVENUE AND OTHER INCOME | $ 252,233 | $ 2,246,725 |
Natural Gas [Member] | ||
REVENUES AND OTHER INCOME: | ||
TOTAL REVENUE AND OTHER INCOME | 27,042 | 273,816 |
Other Liquids [Member] | ||
REVENUES AND OTHER INCOME: | ||
TOTAL REVENUE AND OTHER INCOME | $ 7 | $ 33,028 |
Consolidated Statements Of Chan
Consolidated Statements Of Changes In Stockholders' Equity - USD ($) | Issued Capital [Member] | Retained Earnings/(Accumulated Deficit) [Member] | Other Comprehensive Income (Loss) [Member] | Total |
Beginning Balance, value at Jun. 30, 2016 | $ 105,719,184 | $ (101,455,429) | $ 927,718 | $ 5,191,473 |
Net loss | (2,767,496) | (2,767,496) | ||
Foreign currency translation | (35,701) | (35,701) | ||
Total comprehensive loss for the period | (2,767,496) | (35,701) | (2,803,197) | |
Share based payment, value | 159,506 | |||
Stock based compensation | 711,493 | 711,493 | ||
Issue of share capital | 4,516 | 4,516 | ||
Share issue costs | (44,329) | |||
Ending 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 | (45,461) | (45,461) | ||
Total comprehensive loss for the period | (6,038,866) | (45,461) | (6,084,327) | |
Total 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) |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash flows from operating activities | ||
Receipts from customers | $ 1,498,741 | $ 2,093,069 |
Cash received from commodity derivative financial instruments | (1,625,866) | (1,342,901) |
Payments to suppliers & employees | (4,044,829) | (5,553,017) |
Interest received | 228 | 411 |
Cash payments for abandonment costs | (291,277) | (45,142) |
Net Cash Provided by (Used in) Operating Activities, Continuing Operations, Total | (4,463,003) | (4,847,580) |
Cash flows from investing activities | ||
Proceeds from sale of oil and gas properties | 15,150,000 | |
Payments for plant & equipment | (28,805) | (106,726) |
Payments for exploration and evaluation | (54,212) | (138,715) |
Payments for oil and gas properties | (78,705) | (479,712) |
Net cash flows (used in)/ provided by investing activities | (161,722) | 14,424,847 |
Cash flows from financing activities | ||
Proceeds from issue of share capital | 3,198 | |
Proceeds from borrowings | 450,000 | |
Repayment of borrowings | (35,000) | (11,047,443) |
Payments for costs associated with borrowings | (40,000) | |
Payments for costs associated with capital raising | (3,771) | |
Net cash flows (used in)/ provided by financing activities | 415,000 | (11,088,016) |
Net (decrease)/increase in cash and cash equivalents | (4,209,725) | (1,510,749) |
Cash and cash equivalents at the beginning of the year | 628,778 | 2,654,812 |
Net cashflows provided by operations - discontinued operations | 6,768,727 | 2,236,620 |
Net cashflows used in investing actvities - discontinued operations | (445,997) | (2,718,371) |
Net cashflows used in financing operations -discontinued operations | (1,350,391) | |
Effects of exchange rate changes on cash and cash equivalents | (14,716) | (33,534) |
Cash and cash equivalents at end of year | $ 1,376,676 | $ 628,778 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Jun. 30, 2018 | |
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 realisation of assets and settlement of liabilities in the normal course of business. We incurred a net loss of $6.0 million. the year ended June 30, 2018. As at that date, our total current liabilities of $34.8 million (excluding discontinued operations million exceed our total current assets of $3.5 million (excluding discontinued operations). Additionally, w e are in violation of our debt covenants and have suffered recurring losses from operations. These factors raise substantial doubt over our ability to continue as a going concern and therefore whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the financial report. To address these concerns, we have undertaken the following plan: - We have signed a purchase and sale agreement for the sale of substantially all of our interest in the Foreman Butte project for $40 million. The effective date of this sale is January 1, 2018 and the sale is expected to close October 15, 2018. - We have entered into a forbearance agreement with Mutual of Omaha Bank in order to allow the orderly closing of the pending asset sale - We are continuing to operate the properties in a such a way so as to maximize value should we be required to enter into a sale agreement with another party. While management believes that we will successfully close the pending asset sale transaction or a similarly valued alternative sale transaction there can be no assurances that our efforts will be successful. In addition, given our current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available. The financial report does not include any adjustments relating to the amounts or classification of recorded assets or liabilities that might be necessary if the Company does not continue as a going concern. Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated in consolidation. Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long–lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) certain accrued liabilities; (9) valuation of share-based payments, (10) income taxes and (11) carrying value of exploration and evaluation expenditure. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions through the date of this report for matters that may require recognition or disclosure in these financial statements. Business Segment Information. The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers. Revenue Recognition and Gas Imbalances. Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of completed deliveries where title has transferred. Title to oil sold is typically transferred at the wellhead. The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at June 30, 2018 or 2017. Cash and Cash Equivalents. The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company’s cash management process provides for the daily funding of checks as they are presented to the bank . Accounts Receivable. The components of accounts receivable include the following: June 30 2018 2017 Oil and natural gas sales $ 1,005,217 $ 894,523 Cost recovery from partners 734,912 572,082 Less provision for doubtful debts (75,000) - Other 94,332 83,833 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2018 and 2017 $ 1,759,461 $ 1,550,438 The Company's accounts receivable result from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are primarily from the operators of our various projects, who negotiate the sale of oil and gas to third parties on our behalf. Oil and Gas Properties. Oil and gas properties and equipment consist of the following at June 30: 2018 2017 Proved properties $ 13,181,514 $ 13,114,851 Lease and well equipment 1,169,856 1,140,310 Less accumulated depreciation, depletion and impairment (12,606,419) (12,440,389) $ 1,744,951 $ 1,814,772 Assets held for sale 28,675,890 - Unproved acreage $ - $ 271,078 The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method. Mineral interests and leasehold acquisition costs are depleted over total proved reserves while cost of completed wells and related facilities and equipment are depleted over proved developed producing reserves. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field. The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment. Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Company. Impairment on properties sold is recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term . Assets held for sale In June 2018, we signed a purchase and sale agreement for the sale of the Foreman Butte Project, subject to our retention of a 15% working interest in a portion of the Project (the “Foreman Butte Sale”). This transaction received shareholder approval at a general meeting held on August 13, 2018. The purchase price is $40 million with an effective date of January 1, 2018. The Foreman Butte Project constitutes the majority of our operating assets. Upon closing of the transaction, we will retain a 15% working interest in certain wells in the Home Run Field, which consists of 15 producing wells and 20 PUD locations. The proceeds of the Foreman Butte Sale will be used to repay our credit facility with Mutual of Omaha Bank in full and bring our other accounts payable current. We estimate that after these repayments, we will have no outstanding debt and will retain approximately $6.5 million in cash proceeds from the sale. Exploration and evaluation costs including capitalized exploration written off and dry hole expenses Exploration and evaluation assets are assessed for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. When assessing for impairment consideration is given to but not limited to the following: the period for which Samson has the right to explore; planned and budgeted future exploration expenditure; activities incurred during the year; and activities planned for future periods. If, after having capitalized expenditure under our policy, the Company concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement. During the fiscal year ended June 30, 2018, we expensed $0.2 million in deferred exploration expense in relation to our Cane Creek project area. Impairment The Company recorded impairment charges of $nil million and $0.2 million for the years ended June 30, 2018 and 2017 respectively. The charges in the fiscal year ended June 30, 2017 related to the write down of the value in our oil inventory to lower of cost or net realizable value. 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, 2018 and 2017 was $0. 2 million and $0. 2 million, respectively. Other property and equipment consist of the following at June 30: 2018 2017 Furniture, fittings and equipment $ 1,017,879 $ 990,022 Less accumulated depreciation (775,057) (693,945) $ 242,822 $ 296,077 Derivative Financial Instruments. The Company enters into derivative contracts, primarily collars, swaps and option contracts, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivative instruments are recorded on the balance sheet at fair value. All of the Company's derivative counterparties are major oil companies. The Company has elected not to apply hedge accounting to any of its derivative transactions and consequently, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts in other comprehensive income for those commodity derivatives that qualify as cash flow hedges. Asset Retirement Obligations. The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long–lived asset are recorded at the time the well is spud or acquired. Environmental. The Company is subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non–capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable. The Company is not aware of any material noncompliance with existing laws and regulations. Income Taxes. Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50 % likelihood of being realized upon ultimate settlement. Earnings per Share. Basic earnings (loss) per share are calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding since the impact would be anti-dilutive. When the Company records a net loss, none of the loss is allocated to the unexercised stock options since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, outstanding options will have no dilutive impact to the Company’s basic earnings per share. The following potential common shares relating to options and warrants have been excluded from the calculation of diluted earnings per share as the related impact was anti-dilutive. Year ended June 30, 2018 2017 Dilutive - - Anti–dilutive 314,500,000 287,956,323 Stock-Based Compensation. Stock-based compensation is measured at the estimated grant date fair value of the awards and is recognized on a straight-line basis over the requisite service period (usually the vesting period). The Company recognizes stock-based compensation net of an estimated forfeiture rate, and recognizes compensation expense only for shares that are expected to vest. Compensation expense is then adjusted based on the actual number of awards for which the requisite service period is rendered. Foreign Currency Translation. The functional currency of Samson Oil & Gas Limited (Parent Entity) is Australian dollars, the reason for this being the majority of cash flows of the Parent Entity are denominated in Australian dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S. dollars. The presentation currency of the Consolidated Entity is U.S. dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income. Business Combinations Samson applies the acquisition method in accounting for business combinations. The consideration transferred by the Company is calculated as the sum of the acquisition date fair value of assets transferred, liabilities incurred and any equity interests issued by the Company, which includes the fair value of any asset or liability arising from any contingent consideration arrangements. Acquisition costs are expensed as incurred. The Company treats the acquisition of oil and gas assets as a business combination. The Company recognizes identifiable assets acquired and liabilities assumed in a business combination regardless of whether they have been previously recognized in the acquiree’s financial statements prior to the acquisition. Assets acquired and liabilities assumed are generally measured at their acquisition date fair values. If the fair values of identifiable net assets exceeds the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. Impact of Recently Adopted Accounting Standards. There have been no recently adopted accounting standards that would impact our business. Recently Issued Accounting Pronouncements In August 2014, the FASB issued new guidance related to the disclosures around going concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. This standard has been adopted and the Company has added the appropriate disclosures. In November 2014, the FASB issued ASU No. 2014-16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity. This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted. The Company has adopted this standard and it did not have a material impact on its consolidated financial statements. ASU 2016-02, Leases (Topic 842) This ASU, among other provisions, requires lessees to recognize right of use assets and leases liabilities for all leases not considered short term leases. The ASU is effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years This standard is not expected to have a significant impact on the Company as it does not currently engage in significant leasing activity. ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Update (ASU) 2014-09 provides a new framework for addressing revenue recognition issues and upon its effective date, replaces almost all existing revenue recognition guidance. While the revenue recognition policies of all entities will be impacted by this standard, we do not expect the impact to be significant. For public business entities, the guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We do expect this standard to have a significant impact on our financial reporting of the standards disclosed above that have not yet taken effect. However, we do expect these changes to have an impact with additional disclosures contained in the 10Q for the period ended September 30, 2018 expected. |
Discontinued Operations
Discontinued Operations | 12 Months Ended |
Jun. 30, 2018 | |
Discontinued Operations [Abstract] | |
Discontinued Operations | 2. DISCONTINUED OPERATIONS As of June 30, 2018 the majority of our interest in the wells in the Foreman Butte project were held for sale and therefore have been recognized as discontinued operations for the years ended June 30, 2018 and 2017. . Discontinued Operations Year ended June 30, 2018 2017 Major line items constituting pretax gain (loss) of discontinued operations Oil sales 9,678,832 10,336,307 Gas sales 91,742 162,546 Other liquids 8,864 5,261 Lease operating expense (6,031,983) (7,751,072) Depletion, depreciation and amortization (1,071,959) (1,770,500) Accretion of asset retirement obligations (216,229) (263,964) Amortization of borrowing costs (440,434) (219,810) Interest expense (1,275,137) (1,592,802) Gain/(loss) from discontinued operations 743,696 (1,094,034) Cashflows from Discontinued Operations Cashflows from Operating Activities 6,768,727 2,236,620 Cashflows from Investing Activities (445,997) (2,718,371) Cashflows from Financing Activities (1,350,391) - |
Hedging And Derivative Financia
Hedging And Derivative Financial Instruments | 12 Months Ended |
Jun. 30, 2018 | |
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, 2018, 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 Mutual of Omaha Bank, the provider of the Company’s credit facility. As such no collateral is required by the counterparty. At June 30, 2018 the Company’s open derivative contracts consisted of the following: Collar Product Start Date End Date Volume (BO/Mmbtu) Floor Ceiling WTI 1-Jul-18 31-Dec-18 80,960 $ 45.00 56.00 Henry Hub 1-May-18 31-Dec-18 50,490 $ 2.65 2.90 During the year ended June 30, 2017, the Company recorded a gain of $1.3 million in the Statement of Operations in in derivative instruments. As of June 30, 2017, the derivative instruments were valued at $0.26 million of which, $0.1 million is recorded as a current liability and $0.36 million is recorded as a non-current asset. During the year ended June 30, 2018, the Company recognized $ 2.7 million in the Statement of Operations in loss in derivative instruments. As of June 30, 2018, its derivative instruments were valued at $1.2 million recorded as current liability. See Note 4 for additional fair value disclosures about the Company’s oil and gas derivatives. Price risk Price risk arises from the Company’s exposure to oil and gas prices. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. Sustained weakness in oil and natural gas prices may adversely affect the Company’s financial condition. The Company manages this risk by continually monitoring the oil and gas price and the external factors that may affect it. The Board reviews the risk profile associated with commodity price risk periodically to ensure that it is appropriately managing this risk. Derivatives are used to manage this risk where appropriate. The Board must approve any derivative contracts that are entered into by the Company. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Jun. 30, 2018 | |
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, 2018 and 2017. 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 - - - Fair Value at June 30, 2017 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 628,778 $ - $ - $ - $ 628,778 Derivative Instruments - 167,307 - (167,307) - Non Current Assets: Derivative Instruments - 370,494 - (270,891) 99,603 Current Liabilities Derivative Instruments - 531,267 - (167,307) 363,960 Non Current Liabilities: Derivative Instruments 270,891 (270,891) - (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. 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, 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, 2018 | |
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, 2017 and 2016: 2018 2017 Asset retirement obligations at beginning of period $ 3,456,236 $ 3,750,245 Liabilities incurred or acquired - 226,123 Liabilities settled (73,667) (427,214) Disposition of properties (73,011) (409,683) Accretion expense 34,554 316,765 Asset retirement obligations at end of period 3,344,112 3,456,236 Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) - (300,000) Less current asset retirement obligatons related to assets held for sale (2,509,981) Long-term asset retirement obligations $ 834,131 $ 3,156,236 Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4 % and 13 %. The liabilities incurred in the prior year relate to the liabilities acquired in relation to the Foreman Butte acquisition. |
Income Taxes
Income Taxes | 12 Months Ended |
Jun. 30, 2018 | |
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 2018 2017 Current: Federal $ (732,056) $ - State - - (732,056) - Deferred: Federal (732,056) - State - - Less income tax benefit allocated to discontinued operations Total income tax provision (benefit) $ (1,464,112) $ - 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 (in thousands): June 30 2018 2017 Income tax expense (benefit) at federal statutory rate $ (1,956,277) $ (787,563) Effect of permanent differences and other - US 115,616 - State income taxes (123,694) (34,997) Change in tax rate 11,207,430 US income taxed at a different rate 116,777 Foreign exchange 282,557 Other adjustments - true up of deferred balances (10,819) Alternative minimum tax - - Other - change in deferred tax rate - (239,200) Other 23,507 112,867 Valuation allowance (10,387,153) 948,893 $ (732,056) $ - The components of deferred tax assets and (liabilities) are as follows (in thousands): June 30 2018 2017 Deferred income tax assets: Net operating losses $ 23,674,591 $ 34,581,318 Asset retirement obligation 737,875 1,212,151 Annual leave 51,837 81,130 Abandonment limitation 554,685 554,685 Allowance for doubtful debts 17,560 - Accrued bonus - - Charitable contributions - 882 AMT credit 780,443 780,443 Share based compensation 500,844 500,844 Oil and Gas Property - - Derivative liability 283,458 98,175 Valuation allowance (23,951,026) (34,286,029) Deferred income tax liabilities: Commodity liability - - Amortization - loan costs - - Oil and gas property (1,908,395) (3,523,599) Net deferred income tax assets (liabilities) 732,506 - June 30 2018 2017 Deferred Income Tax Valuation Allowance Balance at July 1 34,286,029 33,337,136 Additions (reductions) to deferred income tax expense (10,387,153) 948,893 Balance at June 30 23,898,876 34,286,029 The Company has tax losses carried forward arising in Australia of $15,509,399 (2017: $ 15,949,783 ). The benefit of these losses of $4,652,820 (2017: $4,784,935 ) 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 $ 84,932,621 (2017: $82,341,738 ). The current year utilization carried back to prior years, is approximately $ nil (2017: $ nil ). 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 2036 . In addition to the above-mentioned Federal carried forward losses in the United States, the Company also has approximately $ 49,189,363 (2017: $ 47,582,073 ) of State carried forward tax losses, with expiry dates between June 2015 and June 2033 . A deferred income tax asset in relation to these losses has not been recognized as realization of the benefit is not regarded as probable. The change in federal corporate income tax rate from 35% to 21% was enacted in 2017 and effective 1/1/18. For 2017, the rate change does impact the calculation of current income tax liability and requires the future rate to be applied to deferred income tax assets and liabilities that exist at 6/30/18. An expense of $ 11,140,774 was recorded to deferred income tax expense for this change. An adjustment to the effective tax rate is also required to reflect the different rates (35% and 21%) applied to currently arising temporary differences for current tax and deferred tax. There is no P&L impact of these adjustments as the valuation allowance will have a corresponding adjustment to offset any changes to the deferred tax asset. In assessing the realizeability 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 realizeablity of the deferred tax assets to be more likely than not. As such, the company has a full valuation allowance offsetting the deferred tax asset. 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. |
Capital Stock Contributed Equit
Capital Stock Contributed Equity | 12 Months Ended |
Jun. 30, 2018 | |
Capital Stock Contributed Equity [Abstract] | |
Capital Stock Contributed Equity | 7. COMMON STOCK Consolidated Entity 2018 2017 3,283,000,444 ordinary fully paid shares including shares to be issued $ 106,743,167 $ 106,390,864 (2017 – 3,283,000,444 ordinary fully paid shares including shares to be issued) Movements in contributed equity for the year 2018 2017 No. of shares $ No. of shares $ Opening balance 3,283,000,444 106,390,864 3,215,854,701 105,719,184 Capital raising (i) - - - - Shares issued upon exercise of options (ii) - - 140,143 4,516 Stock based compensation - shares issued - - 67,005,600 159,506 Stock based compensation - warrants issued - 352,303 - 551,987 Transaction costs incurred - - - (44,329) Shares on issue at balance date 3,283,000,444 106,743,167 3,283,000,444 106,390,864 318,452,166 ordinary shares at $0.02 cents each to raise $6,700,000 in a private placement to certain institutional investors. 290,110,820 ordinary shares at $0.02 cents to raise $5,400,000 in a private placement to certain investors. 114,335,711 ordinary shares to raise $2,716,701. 19,182,812 ordinary shares at 0.026 cents to raise $500,000 in a private placement to certain institutional investors. 109,752,575 ordinary shares at 0.0259 cents to raise $2,850,000 in a private placement to certain institutional investors. i) (ii) During the course of the prior year the Company issue d 140,143 ordinary shares upon the exercise of 140,143 options. The exercise price of 140,143 of the options exercised was A$ 0.038 cents per share/US$ 0.032 cents per shares (average price based on the exchange rate on the date of exercise) to raise US$ 4,516 . |
Cash Flow Statement
Cash Flow Statement | 12 Months Ended |
Jun. 30, 2018 | |
Cash Flow Statement [Abstract] | |
Cash Flow Statement | 8. CASH FLOW STATEMENT Year ended June 30 2018 2017 A reconciliation of the net loss to the net cash provided by operations is as follows: Net loss after tax $ (6,038,866) $ (2,767,496) Depreciation 1,237,989 1,989,135 Accretion of asset retirement obligations 250,783 316,765 Share based payments 352,303 711,493 Exploration and evaluation expenditures 325,304 78,391 Impairment losses of oil and gas properties - 244,480 Borrowing costs 440,434 219,810 Change in fair value of derivative instruments 946,438 (2,640,373) Bargain purchase on acquisition - - Profit on sale of assets (178,407) (2,250,070) Provision for doubtful debts 75,000 - Income tax benefit (732,056) Non cash other income - (126,265) Changes in assets and liabilities: Decrease in receivables (121,193) 743,041 Increase/(decrease) in employee benefits 1,766 54,563 Increase in payables 5,746,229 815,566 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 2,305,724 $ (2,610,960) |
Credit Facility
Credit Facility | 12 Months Ended |
Jun. 30, 2018 | |
Credit Facility [Abstract] | |
Credit Facility | 9. CREDIT FACILITY June 30, 2018 2017 Credit facility at beginning of period $ 23,419,749 $ 30,500,000 Cash advanced under facility 450,000 - Assumption of promissory note - 4,000,000 Repayments (2,192) (11,080,251) Credit facility at end of period $ 23,867,557 $ 23,419,749 Funds available for drawdown under the facility - 580,251 In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. $11.5 million was repaid in October 2016, following the closing of the sale of the North Stockyard asset. As a result of this amendment to the facility agreement, the following changes were made to the original facility agreement: · The addition of more restrictive financial covenants (including the debt to EBITDA ratio and the minimum liquidity requirement); · Increases in the interest rate and unused facility fee; · The addition of a minimum hedging requirement of 75% of forecasted production; · A requirement to reduce our general and administrative costs from $6 million per year to $3 million per year; · A requirement to raise $5 million in equity on or before September 30, 2016 (which was extended to November 15, 2016 and completed in October 31, 2016); · A requirement to pay down at least $10 million of the loan by June 30, 2016 (which was increased to $11.5 million and extended to and completed in October 31, 2016 following the agreement to sell our interest in the North Stockyard field for $15 million); and · The addition of a monthly cash flow sweep whereby 50% of cash operating income will be used to repay outstanding borrowings under the Credit Agreement. The current borrowing base is $24 million and is fully drawn as at September 28, 2018. We have entered into a forbearance agreement with Mutual of Omaha to allow the closure of the orderly pending asset sale, expected to be October 15, 2018. Should that sale not close in a timely fashion, Mutual of Omaha bank will have the right to seek alternative remedies to facilitate the repayment of the facility. In January 2014, we entered into a $25.0 million credit facility with Mutual of Omaha Bank. The current borrowing base is $24.0 million, of which $23.5 million was drawn at June 30, 2017. In June 2017, the facility was extended to October 31, 2018 and the interest was changed to the prime rate plus between 1% and 2.5%. This equates to between 5.25% and 6.75%. All of our assets are pledged as collateral under this facility. As at June 30, 2017 and June 30, 2018, we were in breach of earnings and liquidity covenants with respect to the facility. We incurred $0.4 million in borrowing costs when we completed the first drawdown, which have were deferred, however have now been written off to Discontinued Operations following the entering of the original forbearance agreement. |
Share-Based Payments
Share-Based Payments | 12 Months Ended |
Jun. 30, 2018 | |
Share-Based Payments [Abstract] | |
Share-Based Payments | 10. SHARE-BASED PAYMENTS (all figures are in Australian dollars in this note unless noted otherwise) To convert June 30, 2018 balances denominated in Australian dollars to U.S. dollars, we used the June 30, 2018 and 2017 Federal Reserve Bank of Australia (www.rba.gov.au) closing exchange rates of 0.7692 and 0.768. U.S. dollars per Australian dollar, respectively. All dollars in this footnote are Australian dollars, except where stated 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. During the year ended June 30, 2017 320,000,000 options were issued to certain employees and directors. The options vest on November 16 and 17, 2017 and expire on November 17, 2026. The exercise price of 48,000,000 options is A$0.7 cents and the exercise price on 272,000,000 is $0.55 cents. Based on the following assumptions, the options have fair market value on grant date of A$0.38 cents. Share price at grant date (cents – Australian) 0.4 Exercise price (cents - Australian) 0.70 Time to expiry (years) 10 Risk free rate (%) 2.72 Share price volatility (%) 119.96 Based on the following assumptions, the options have a fair market value on grant date of A$0.37 cents Share price at grant date (cents – Australian) 0.4 Exercise price (cents - Australian) 0.55 Time to expiry (years) 10 Risk free rate (%) 2.72 Share price volatility (%) 119.96 No options were issued during the year ended June 30, 2018 as share based payments. As of June 30 , 2017, there was US$ 0.4 million in unrecognized compensation cost related to stock options. This was expensed during the period from July 1, 2017 to the vesting date of the options on November 17, 2017. 5,500,000 options were cancelled as an employee resigned prior to meeting the vesting condition. The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 2018 and 2017 (all values in AUD unless otherwise noted): 2018 2017 Number Weighted Aggregate Number Weighted Average Intrinsic Average Exercise Value of Exercise Price – cents Options/Warrants Price – cents (AUD) cents (AUD) (AUD) (1) Outstanding, start of period 411,033,246 1.18 320,615,486 4.60 Granted - 320,000,000 0.57 Exercised - (140,143) 3.80 Cancelled/expired (96,533,246) 3.80 (229,442,097) 3.80 Outstanding, end of period 314,500,000 0.5700 - 411,033,246 1.18 Exercisable, end of period 314,500,000 0.5700 91,033,246 3.80 (1) The intrinsic value of a stock option is the amount by which the market value is (less than)/exceeds the exercise price at the Balance Date. The aggregate intrinsic value of options exercised in 2017 was (AUD 4,747 ). No options were exercised during 2018. Additional information related to options and warrants outstanding at June 30, 2018 is as follows (outstanding): Options/Warrants Outstanding and Exercisable Range of Number Weighted Weighted Exercise Outstanding Average Average Prices Remaining Exercise Contractual Prices Life - years Cents per share 0.7 cents 48,000,000 8.42 0.7 0.55 cents 266,500,000 8.42 0.55 314,500,000 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Jun. 30, 2018 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 11. RELATED PARTY TRANSACTIONS There were no related party transactions during the years ended June 30, 2018 and 2017. |
Commitments
Commitments | 12 Months Ended |
Jun. 30, 2018 | |
Commitments [Abstract] | |
Commitments | 12. COMMITMENTS Lease commitments over the next five years are as follows: Total 2019 2020 2021 2022 2023 Thereafter Leases 391,974 123,873 127,845 131,309 8,947 - - (2) Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Leases –The Company has entered into lease agreements for office space in Denver, Colorado and Perth, Western Australia. As of June 30, 2018, future minimum lease payments under operating leases that have initial or remaining non–cancelable terms in excess of one year are $ 123,873 in 2019, $ 127,845 in 2020, $131,309 in 2021, $8,947 in 2022. Net rent expense incurred for office space was $ 214,650 and $153,375 in 2018 and 2017, respe c tively . |
Contingencies
Contingencies | 12 Months Ended |
Jun. 30, 2018 | |
Contingencies [Abstract] | |
Contingencies | 13. 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, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events | 14. SUBSEQUENT EVENTS There have been no material subsequent events through the date of filing. |
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, 2018 | |
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 | 15. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES, INCLUSIVE OF DISCONTINUED OPERATIONS (UNAUDITED) Oil and Gas Reserves Given the pending sale at June 30, 2018, our fiscal year-end petroleum reserves report was prepared internally by knowledgeable officers and employees of the Company for the current year. The report was based upon our internal review of the property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sales of production, geoscience and engineering data, and other information we gather. We prepared our estimates by use of standard geological and engineering methods generally accepted by the petroleum industry. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the un-weighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and year-end costs. The proved reserve estimates represent our net revenue interest in our properties. Our reserves were prepared by a practitioner with 22 years of industry experience in geologic engineering and a Bachelor of Science in Geological Engineering from Colorado School of Mines. Additionally, our Chief Executive Officer is responsible for overseeing the preparation of the Company’s reserves report. The CEO is a petroleum geologist who holds an associateship in applied geology and has over 45 years of relevant experience in the oil and gas industry. Estimated Proved Reserves Proved reserves are those quantities of hydrocarbons which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations. As commodity prices decline, the commercially viability of wells change and reserve quantities may decrease. Proved reserves can be categorized as developed or undeveloped. Capitalized Costs Incurred Costs incurred for oil and natural gas exploration, development and acquisition are summarized below. Year ended June 30, 2018 2017 Development 13,272 2,458,276 Discontinued Operations 68,865 - Undeveloped capitalized acreage - 50,375 Total costs incurred $ 82,137 $ 2,508,651 Estimated Proved Reserves Proved reserves are those quantities of hydrocarbons which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations. As commodity prices decline, the commercially viability of wells change and reserve quantities may decrease. Proved reserves can be categorized as developed or undeveloped. Year ended June 30, 2018 Year ended June 30, 2017 Oil Gas Total Oil Gas Total Mbbls MMcf MBOE Mbbls MMcf MBOE Beginning of year 5,359 3,565 5,955 9,982 8,593 11,415 Revisions of previous quantity estimates (1,654) (2,246) (2,028) (2,851) (2,474) (3,263) Extensions and discoveries - - - - - - Sale of reserves in place - - - (1,475) (2,396) (1,874) Acquisitions - - - - - - Production (190) (27) (195) (297) (158) (323) End of year 3,515 1,292 3,732 5,359 3,565 5,955 Proved developed producing reserves 73 60 84 3,020 1,575 3,285 Proved developed non producing 32 43 39 134 224 171 Proved undeveloped reserves 308 251 350 2,205 1,766 2,499 Proved developed producing reserves - held for sale 2,590 563 2,685 - - - Proved developed non producing - held for sale 512 375 575 - - - Total proved reserves 3,515 1,292 3,732 5,359 3,565 5,955 Revisions of previous quantity estimates The downward revision recorded for the year ended June 30, 2017 relates to our current drilling plan for our PUD locations. In the prior year, we anticipated drilling them as new 10,000 foot lateral horizontal wells. Upon further technical review, we now plan to drill the PUD wells as 5,000 foot laterals out of an existing well bore. The shortening of the lateral length lead to a decrease in the volume of reserves associated with these PUDs. The downward revision in the current year relates to our recognition of PUDs. Due to the continued lack of capital available to drill these PUDs, the decision was made to sell substantially all of the wells in the Foreman Butte project area. We have retained a 15% working interest in certain PUDs and we have recognized that value in our reserves at June 30, 2018. Sales of Reserves in Place The reserves held for sale relate to the sale of the majority of our interest in the Foreman Butte project. This sale is expected to close on October 15, 2018. The sale of reserves in place during the fiscal year ended June 30, 2017 consists of proved reserves (net of production prior to sale) in the North Stockyard field in North Dakota and the State GC field in New Mexico. All reserves were proved developed producing. Developed Reserves Developed reserves are those reserves expected to be recovered from existing wells, with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Proved Developed Producing Reserves At June 30, 2018 our proved developed producing reserves primarily relate to our working interest in producing wells in our Foreman Butte project area in North Dakota and Montana. Proved Developed Not Producing (PDNP) PDNP reserves are those estimated proved reserves expected to be recovered from existing wells where a workover is required to re-establish production. As of June 30, 2017, the PDNP reserves were 171 MBOEAs of June 30, 2018, the PDNP reserves were 39 MBOE. These primarily related to our retained interest in the Foreman Butte project. This work is expected to be performed as capital allows. Proved Undeveloped Reserves Proved undeveloped reserves (PUD) are those reserves expected to be recovered from new wells on undeveloped acreage. Due to the continued lack of capital available to drill these PUDs, the decision was made to sell substantially all of the wells in the Foreman Butte project area. We have retained a 15% working interest in certain PUDs and we have recognized that value in our reserves at June 30, 2018 as following the sale, we will have the working capital available to develop these locations. During the year ended June 30, 2017 through further technical review, we changed our plan with respect to the drilling the PUDs. This reduced the reserves volumes associated with the PUDs but did not change the reserve value associated with the PUDs due to a decrease in the estimated drilling costs. We currently have the permits to drill 4 PUDs and have commenced sourcing the appropriate rig and other contractors and equipment required. While we did not convert any PUDs during the year ended June 30, 2018, we have made considerable progress on their development through the pending sale. Standardized Measure of Discounted Future Net Cash Flows Future hydrocarbon sales and production and development costs have been estimated using a 12 month average price for the commodity prices for June 30, 2018 and 2017 and costs in effect at the end of the periods indicated. The average 12 month historical average of the first of the month prices used for natural gas for June 30, 2018 and 2017 were $2.95 and $3.01 per Mcf, respectively. The 12-month historical average of the first of the month prices used for oil for June 30, 2018 and 2017 were $57.67 and $ 48.95 per barrel of oil, respectively . Future cash flows were reduced by estimated future development, abandonment and production costs based on period–end costs. No deductions were made for general overhead, depletion, depreciation and amortization or any indirect costs. All cash flows are discounted at 10 %. Changes in demand for hydrocarbons, inflation and other factors make such estimates inherently imprecise and subject to substantial revisions. This table should not be construed to be an estimate of current market value of the proved reserves attributable to Samson. Samson has not disclosed the impact of taxes in the future cash flows for the years ended June 30, 2018 and 2017 as given Samson’s extensive net operating losses carried forward, its history of loss making and the significant value of intangible costs incurred when developing its proved undeveloped locations, for which an immediate tax deduction is currently available, it is unlikely Samson will pay tax in the future based on current commodity pricing. 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, 2018 2017 Future cash inflows $ 187,249 $ 237,490 Future production costs (99,620) (91,920) Future development costs (1,642) (13,367) Future income taxes - - Future net cashflows 85,987 132,203 10 % discount (38,325) (66,941) Standardized measure of discounted future net cash flows relating to proved reserves $ 47,662 $ 65,262 The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2018 and June 30, 2017 are as follows (in US$’000’s): Fiscal Year Ended June 30 2018 2017 Beginning of year $ 65,262 $ 66,747 Sales of oil and gas produced during the period, net of production costs (3,902) (3,122) Net changes in prices and production costs 2,822 1,601 Previously estimated development costs incurred during the period - - Changes in estimates of future development costs (11,625) 22,929 Extensions and discoveries - - Revisions of previous quantity estimates and other (10,088) (21,078) Sale of reserves in place - (10,445) Purchase of reserves in place - - Change in future income taxes - - Accretion of discount 6,526 6,675 Other (1,333) 1,955 Balance at end of year $ 47,662 $ 65,262 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 cashflows. |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2015 | |
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. These financial statements have been prepared on the going concern basis, which contemplates the continuity of normal business activities and the realisation of assets and settlement of liabilities in the normal course of business. We incurred a net loss of $6.0 million. the year ended June 30, 2018. As at that date, our total current liabilities of $34.8 million (excluding discontinued operations million exceed our total current assets of $3.5 million (excluding discontinued operations). Additionally, w e are in violation of our debt covenants and have suffered recurring losses from operations. These factors raise substantial doubt over our ability to continue as a going concern and therefore whether we will realize our assets and extinguish our liabilities in the normal course of business and at the amounts stated in the financial report. To address these concerns, we have undertaken the following plan: - We have signed a purchase and sale agreement for the sale of substantially all of our interest in the Foreman Butte project for $40 million. The effective date of this sale is January 1, 2018 and the sale is expected to close October 15, 2018. - We have entered into a forbearance agreement with Mutual of Omaha Bank in order to allow the orderly closing of the pending asset sale - We are continuing to operate the properties in a such a way so as to maximize value should we be required to enter into a sale agreement with another party. While management believes that we will successfully close the pending asset sale transaction or a similarly valued alternative sale transaction there can be no assurances that our efforts will be successful. In addition, given our current financial situation we may be forced to accept terms on these transactions that are less favorable than would be otherwise available. The financial report does not include any adjustments relating to the amounts or classification of recorded assets or liabilities that might be necessary if the Company does not continue as a going concern. Comparatives. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). | ||
Principles Of Consolidation | Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are wholly owned. Significant intercompany balances and transactions have been eliminated in consolidation. | ||
Use Of Estimates | Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and gas reserves; (2) cash flow estimates used in impairment tests of long–lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity and interest derivative instruments; (8) certain accrued liabilities; (9) valuation of share-based payments, (10) income taxes and (11) carrying value of exploration and evaluation expenditure. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company has evaluated subsequent events and transactions through the date of this report for matters that may require recognition or disclosure in these financial statements. | ||
Business Segment Information | Business Segment Information. The Company has evaluated how it is organized and managed and has identified only one operating segment, which is the exploration and production of crude oil, natural gas and natural gas liquids. All of the Company's operations and assets are located in the United States, and all of its revenues are attributable to United States customers. | ||
Revenue Recognition And Gas Imbalances | Revenue Recognition and Gas Imbalances. Revenues from the sale of natural gas and crude oil are recognized when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured and evidenced by a contract. This generally occurs when oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of completed deliveries where title has transferred. Title to oil sold is typically transferred at the wellhead. The Company uses the entitlement method of accounting for natural gas revenues. Under this method, revenues are recognized based on actual production of natural gas. The Company incurs production gas volume imbalances in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under–deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over– and under– deliveries or by cash settlement, as required by applicable contracts. The Company's production imbalances were not material at June 30, 2018 or 2017. | ||
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 . | ||
Accounts Receivable | Accounts Receivable. The components of accounts receivable include the following: June 30 2018 2017 Oil and natural gas sales $ 1,005,217 $ 894,523 Cost recovery from partners 734,912 572,082 Less provision for doubtful debts (75,000) - Other 94,332 83,833 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2018 and 2017 $ 1,759,461 $ 1,550,438 The Company's accounts receivable result from (i) oil and natural gas sales to oil and intrastate gas pipeline companies and (ii) billings to joint working interest partners in properties operated by the Company. The Company's trade and accrued production receivables are primarily from the operators of our various projects, who negotiate the sale of oil and gas to third parties on our behalf. | ||
Oil And Natural Gas Properties | Oil and Gas Properties. Oil and gas properties and equipment consist of the following at June 30: 2018 2017 Proved properties $ 13,181,514 $ 13,114,851 Lease and well equipment 1,169,856 1,140,310 Less accumulated depreciation, depletion and impairment (12,606,419) (12,440,389) $ 1,744,951 $ 1,814,772 Assets held for sale 28,675,890 - Unproved acreage $ - $ 271,078 The Company accounts for its oil and gas exploration and development costs using the successful efforts method. Geological and geophysical costs are expensed as incurred. Exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The costs of development wells are capitalized whether productive or nonproductive. The provision for depletion of oil and gas properties is calculated on a field–by–field basis using the unit–of–production method. Mineral interests and leasehold acquisition costs are depleted over total proved reserves while cost of completed wells and related facilities and equipment are depleted over proved developed producing reserves. If the estimates of total proved or proved developed reserves decline, the rate at which the Company records depreciation, depletion and amortization (DD&A) expense increases, which in turn reduces net earnings. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic to drill for and produce higher cost fields. The Company is unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of its development program, as well as future economic conditions. Changes in reserves are applied on a prospective basis. As wells are drilled in a field with proved undeveloped reserves or unproved reserves, a portion of the acquisition costs are either re–designated as proved developed or expensed, as appropriate. In fields with multiple potential drilling sites, the Company determines the amount of the acquisition cost to re–designate or expense through a systematic and rational basis that considers the total expected wells to be drilled in that field. The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected future cash flows of its oil and gas properties and compares these undiscounted future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk associated with realizing the projected cash flows. Unproved oil and gas properties are assessed periodically for impairment on a field by field (consistent with the fields used for the calculation of depletion, depreciation and amortization) basis based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks or future plans to develop acreage and allocate capital. When the Company has allocated fair values to significant unproved property (probable reserves) as the result of a business combination or other purchase of proved and unproved properties, it uses a future cash flow analysis to assess the property for impairment. Gains on sales of proved and unproved properties are only recognized when there is no uncertainty about the recovery of costs applicable to any interest retained or where there is no substantial obligation for future performance by the Company. Impairment on properties sold is recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value. In determining whether an unproved property is impaired, the Company considers numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term . Assets held for sale In June 2018, we signed a purchase and sale agreement for the sale of the Foreman Butte Project, subject to our retention of a 15% working interest in a portion of the Project (the “Foreman Butte Sale”). This transaction received shareholder approval at a general meeting held on August 13, 2018. The purchase price is $40 million with an effective date of January 1, 2018. The Foreman Butte Project constitutes the majority of our operating assets. Upon closing of the transaction, we will retain a 15% working interest in certain wells in the Home Run Field, which consists of 15 producing wells and 20 PUD locations. The proceeds of the Foreman Butte Sale will be used to repay our credit facility with Mutual of Omaha Bank in full and bring our other accounts payable current. We estimate that after these repayments, we will have no outstanding debt and will retain approximately $6.5 million in cash proceeds from the sale. | ||
Exploration Written Off, Including Dry Hole Expenses | Exploration and evaluation costs including capitalized exploration written off and dry hole expenses Exploration and evaluation assets are assessed for impairment when facts and circumstances indicate that the carrying amount of an exploration and evaluation asset may exceed its recoverable amount. When assessing for impairment consideration is given to but not limited to the following: the period for which Samson has the right to explore; planned and budgeted future exploration expenditure; activities incurred during the year; and activities planned for future periods. If, after having capitalized expenditure under our policy, the Company concludes that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement. During the fiscal year ended June 30, 2018, we expensed $0.2 million in deferred exploration expense in relation to our Cane Creek project area. | ||
Impairment | Impairment The Company recorded impairment charges of $nil million and $0.2 million for the years ended June 30, 2018 and 2017 respectively. The charges in the fiscal year ended June 30, 2017 related to the write down of the value in our oil inventory to lower of cost or net realizable value. | ||
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, 2018 and 2017 was $0. 2 million and $0. 2 million, respectively. Other property and equipment consist of the following at June 30: 2018 2017 Furniture, fittings and equipment $ 1,017,879 $ 990,022 Less accumulated depreciation (775,057) (693,945) $ 242,822 $ 296,077 | ||
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. | ||
Earnings Per Share | Earnings per Share. Basic earnings (loss) per share are calculated by dividing net earnings (loss) attributable to common stock by the weighted average number of shares outstanding for the period. Under the treasury stock method, diluted earnings per share is calculated by dividing net earnings (loss) by the weighted average number of shares outstanding including all potentially dilutive common shares. In the event of a net loss, no potential common shares are included in the calculation of shares outstanding since the impact would be anti-dilutive. When the Company records a net loss, none of the loss is allocated to the unexercised stock options since the securities are not obligated to share in Company losses. Consequently, in periods of net loss, outstanding options will have no dilutive impact to the Company’s basic earnings per share. The following potential common shares relating to options and warrants have been excluded from the calculation of diluted earnings per share as the related impact was anti-dilutive. Year ended June 30, 2018 2017 Dilutive - - Anti–dilutive 314,500,000 287,956,323 | ||
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 Consolidated Entity is U.S. dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income. | ||
New Accounting Pronouncements, Policy [Policy Text Block] | Impact of Recently Adopted Accounting Standards. There have been no recently adopted accounting standards that would impact our business. Recently Issued Accounting Pronouncements | Impact of Recently Adopted Accounting Standards. There have been no recently adopted accounting standards that would impact our business. Recently Issued Accounting Pronouncements In August 2014, the FASB issued new guidance related to the disclosures around going concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. This standard has been adopted and the Company has added the appropriate disclosures. In November 2014, the FASB issued ASU No. 2014-16, which updates authoritative guidance for derivatives and hedging instruments, specifically in determining whether the host contract in a hybrid financial instrument issued in the form of a share is more akin to debt or to equity. This guidance is effective for the annual period beginning after December 15, 2015; early adoption is permitted. The Company has adopted this standard and it did not have a material impact on its consolidated financial statements. ASU 2016-02, Leases (Topic 842) This ASU, among other provisions, requires lessees to recognize right of use assets and leases liabilities for all leases not considered short term leases. The ASU is effective for public business entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years This standard is not expected to have a significant impact on the Company as it does not currently engage in significant leasing activity. ASU 2014-09, Revenue from Contracts with Customers (Topic 606) Accounting Standards Update (ASU) 2014-09 provides a new framework for addressing revenue recognition issues and upon its effective date, replaces almost all existing revenue recognition guidance. While the revenue recognition policies of all entities will be impacted by this standard, we do not expect the impact to be significant. For public business entities, the guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We do expect this standard to have a significant impact on our financial reporting of the standards disclosed above that have not yet taken effect. However, we do expect these changes to have an impact with additional disclosures contained in the 10Q for the period ended September 30, 2018 expected. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Summary Of Significant Accounting Policies [Abstract] | |
Schedule Of Components Of Accounts Receivable | June 30 2018 2017 Oil and natural gas sales $ 1,005,217 $ 894,523 Cost recovery from partners 734,912 572,082 Less provision for doubtful debts (75,000) - Other 94,332 83,833 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2018 and 2017 $ 1,759,461 $ 1,550,438 |
Schedule Of Other Property And Equipment | 2018 2017 Furniture, fittings and equipment $ 1,017,879 $ 990,022 Less accumulated depreciation (775,057) (693,945) $ 242,822 $ 296,077 |
Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities | Year ended June 30, 2018 2017 Dilutive - - Anti–dilutive 314,500,000 287,956,323 |
Discontinued Operations (Tables
Discontinued Operations (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Discontinued Operations [Abstract] | |
Schedule Of Earnings From Discontinued Operations, Net Of Income Tax | Discontinued Operations Year ended June 30, 2018 2017 Major line items constituting pretax gain (loss) of discontinued operations Oil sales 9,678,832 10,336,307 Gas sales 91,742 162,546 Other liquids 8,864 5,261 Lease operating expense (6,031,983) (7,751,072) Depletion, depreciation and amortization (1,071,959) (1,770,500) Accretion of asset retirement obligations (216,229) (263,964) Amortization of borrowing costs (440,434) (219,810) Interest expense (1,275,137) (1,592,802) Gain/(loss) from discontinued operations 743,696 (1,094,034) Cashflows from Discontinued Operations Cashflows from Operating Activities 6,768,727 2,236,620 Cashflows from Investing Activities (445,997) (2,718,371) Cashflows from Financing Activities (1,350,391) - |
Hedging And Derivative Financ_2
Hedging And Derivative Financial Instruments (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Hedging And Derivative Financial Instruments [Abstract] | |
Schedule Of Open Derivative Contracts | During the year ended June 30, 2017, the Company recorded a gain of $1.3 million in the Statement of Operations in in derivative instruments. As of June 30, 2017, the derivative instruments were valued at $0.26 million of which, $0.1 million is recorded as a current liability and $0.36 million is recorded as a non-current asset. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Fair Value Measurements [Abstract] | |
Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis | 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 - - - Fair Value at June 30, 2017 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 628,778 $ - $ - $ - $ 628,778 Derivative Instruments - 167,307 - (167,307) - Non Current Assets: Derivative Instruments - 370,494 - (270,891) 99,603 Current Liabilities Derivative Instruments - 531,267 - (167,307) 363,960 Non Current Liabilities: Derivative Instruments 270,891 (270,891) - |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Asset Retirement Obligations [Abstract] | |
Summary Of Activities Of Asset Retirement Obligations | 2018 2017 Asset retirement obligations at beginning of period $ 3,456,236 $ 3,750,245 Liabilities incurred or acquired - 226,123 Liabilities settled (73,667) (427,214) Disposition of properties (73,011) (409,683) Accretion expense 34,554 316,765 Asset retirement obligations at end of period 3,344,112 3,456,236 Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) - (300,000) Less current asset retirement obligatons related to assets held for sale (2,509,981) Long-term asset retirement obligations $ 834,131 $ 3,156,236 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Income Taxes [Abstract] | ||
Schedule Of Components Of Income Tax Provision (Benefit) | June 30 2018 2017 Current: Federal $ (732,056) $ - State - - (732,056) - Deferred: Federal (732,056) - State - - Less income tax benefit allocated to discontinued operations Total income tax provision (benefit) $ (1,464,112) $ - | |
Schedule Of Effective Income tax Rate Reconciliation | June 30 2018 2017 Income tax expense (benefit) at federal statutory rate $ (1,956,277) $ (787,563) Effect of permanent differences and other - US 115,616 - State income taxes (123,694) (34,997) Change in tax rate 11,207,430 US income taxed at a different rate 116,777 Foreign exchange 282,557 Other adjustments - true up of deferred balances (10,819) Alternative minimum tax - - Other - change in deferred tax rate - (239,200) Other 23,507 112,867 Valuation allowance (10,387,153) 948,893 $ (732,056) $ - | |
Schedule Of Components Of Deferred Tax Assets and (Liabilities) | June 30 2018 2017 Deferred income tax assets: Net operating losses $ 23,674,591 $ 34,581,318 Asset retirement obligation 737,875 1,212,151 Annual leave 51,837 81,130 Abandonment limitation 554,685 554,685 Allowance for doubtful debts 17,560 - Accrued bonus - - Charitable contributions - 882 AMT credit 780,443 780,443 Share based compensation 500,844 500,844 Oil and Gas Property - - Derivative liability 283,458 98,175 Valuation allowance (23,951,026) (34,286,029) Deferred income tax liabilities: Commodity liability - - Amortization - loan costs - - Oil and gas property (1,908,395) (3,523,599) Net deferred income tax assets (liabilities) 732,506 - | |
Summary Of Valuation Allowance | June 30 2018 2017 Deferred Income Tax Valuation Allowance Balance at July 1 34,286,029 33,337,136 Additions (reductions) to deferred income tax expense (10,387,153) 948,893 Balance at June 30 23,898,876 34,286,029 | |
Reconciliation Of Gross Uncertain Tax Positions | |
Capital Stock Contributed Equ_2
Capital Stock Contributed Equity (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Capital Stock Contributed Equity [Abstract] | |
Contributed Equity | Consolidated Entity 2018 2017 3,283,000,444 ordinary fully paid shares including shares to be issued $ 106,743,167 $ 106,390,864 (2017 – 3,283,000,444 ordinary fully paid shares including shares to be issued) |
Movements In Contributed Equity For The Year | Movements in contributed equity for the year 2018 2017 No. of shares $ No. of shares $ Opening balance 3,283,000,444 106,390,864 3,215,854,701 105,719,184 Capital raising (i) - - - - Shares issued upon exercise of options (ii) - - 140,143 4,516 Stock based compensation - shares issued - - 67,005,600 159,506 Stock based compensation - warrants issued - 352,303 - 551,987 Transaction costs incurred - - - (44,329) Shares on issue at balance date 3,283,000,444 106,743,167 3,283,000,444 106,390,864 318,452,166 ordinary shares at $0.02 cents each to raise $6,700,000 in a private placement to certain institutional investors. 290,110,820 ordinary shares at $0.02 cents to raise $5,400,000 in a private placement to certain investors. 114,335,711 ordinary shares to raise $2,716,701. 19,182,812 ordinary shares at 0.026 cents to raise $500,000 in a private placement to certain institutional investors. 109,752,575 ordinary shares at 0.0259 cents to raise $2,850,000 in a private placement to certain institutional investors. i) (ii) During the course of the prior year the Company issue d 140,143 ordinary shares upon the exercise of 140,143 options. |
Cash Flow Statement (Tables)
Cash Flow Statement (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Cash Flow Statement [Abstract] | |
Schedule Of Cash Flow Statement | Year ended June 30 2018 2017 A reconciliation of the net loss to the net cash provided by operations is as follows: Net loss after tax $ (6,038,866) $ (2,767,496) Depreciation 1,237,989 1,989,135 Accretion of asset retirement obligations 250,783 316,765 Share based payments 352,303 711,493 Exploration and evaluation expenditures 325,304 78,391 Impairment losses of oil and gas properties - 244,480 Borrowing costs 440,434 219,810 Change in fair value of derivative instruments 946,438 (2,640,373) Bargain purchase on acquisition - - Profit on sale of assets (178,407) (2,250,070) Provision for doubtful debts 75,000 - Income tax benefit (732,056) Non cash other income - (126,265) Changes in assets and liabilities: Decrease in receivables (121,193) 743,041 Increase/(decrease) in employee benefits 1,766 54,563 Increase in payables 5,746,229 815,566 NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 2,305,724 $ (2,610,960) |
Credit Facility (Tables)
Credit Facility (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Credit Facility [Abstract] | |
Schedule of Credit Facilities | June 30, 2018 2017 Credit facility at beginning of period $ 23,419,749 $ 30,500,000 Cash advanced under facility 450,000 - Assumption of promissory note - 4,000,000 Repayments (2,192) (11,080,251) Credit facility at end of period $ 23,867,557 $ 23,419,749 Funds available for drawdown under the facility - 580,251 |
Share-Based Payments (Tables)
Share-Based Payments (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Share-Based Payments [Abstract] | |
Schedule Of Additional Information Related To Options Outstanding | Options/Warrants Outstanding and Exercisable Range of Number Weighted Weighted Exercise Outstanding Average Average Prices Remaining Exercise Contractual Prices Life - years Cents per share 0.7 cents 48,000,000 8.42 0.7 0.55 cents 266,500,000 8.42 0.55 314,500,000 |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Jun. 30, 2018 | |
Commitments [Abstract] | |
Contractual Obligations | Total 2019 2020 2021 2022 2023 Thereafter Leases 391,974 123,873 127,845 131,309 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, 2018 | Jun. 30, 2017 | |
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, 2018 2017 Development 13,272 2,458,276 Discontinued Operations 68,865 - Undeveloped capitalized acreage - 50,375 Total costs incurred $ 82,137 $ 2,508,651 | |
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities | Year ended June 30, 2018 Year ended June 30, 2017 Oil Gas Total Oil Gas Total Mbbls MMcf MBOE Mbbls MMcf MBOE Beginning of year 5,359 3,565 5,955 9,982 8,593 11,415 Revisions of previous quantity estimates (1,654) (2,246) (2,028) (2,851) (2,474) (3,263) Extensions and discoveries - - - - - - Sale of reserves in place - - - (1,475) (2,396) (1,874) Acquisitions - - - - - - Production (190) (27) (195) (297) (158) (323) End of year 3,515 1,292 3,732 5,359 3,565 5,955 Proved developed producing reserves 73 60 84 3,020 1,575 3,285 Proved developed non producing 32 43 39 134 224 171 Proved undeveloped reserves 308 251 350 2,205 1,766 2,499 Proved developed producing reserves - held for sale 2,590 563 2,685 - - - Proved developed non producing - held for sale 512 375 575 - - - Total proved reserves 3,515 1,292 3,732 5,359 3,565 5,955 | |
Schedule Of Estimated Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Reserves | As at June 30, 2018 2017 Future cash inflows $ 187,249 $ 237,490 Future production costs (99,620) (91,920) Future development costs (1,642) (13,367) Future income taxes - - Future net cashflows 85,987 132,203 10 % discount (38,325) (66,941) Standardized measure of discounted future net cash flows relating to proved reserves $ 47,662 $ 65,262 | |
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Fiscal Year Ended June 30 2018 2017 Beginning of year $ 65,262 $ 66,747 Sales of oil and gas produced during the period, net of production costs (3,902) (3,122) Net changes in prices and production costs 2,822 1,601 Previously estimated development costs incurred during the period - - Changes in estimates of future development costs (11,625) 22,929 Extensions and discoveries - - Revisions of previous quantity estimates and other (10,088) (21,078) Sale of reserves in place - (10,445) Purchase of reserves in place - - Change in future income taxes - - Accretion of discount 6,526 6,675 Other (1,333) 1,955 Balance at end of year $ 47,662 $ 65,262 |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | |
Jun. 30, 2018USD ($)segment | Jun. 30, 2017USD ($) | |
Significant Accounting Policies [Line Items] | ||
Number of operating segments | segment | 1 | |
Impairment of oil and natural gas properties | $ 244,480 | |
Depreciation and amortization | $ 166,030 | 218,635 |
Minimum percentage of likelihood tax benefits recognized from uncertain tax position, reasonably possible upon settlement | 50.00% | |
Proved properties | $ 13,181,514 | 13,114,851 |
Other Property And Equipment [Member] | ||
Significant Accounting Policies [Line Items] | ||
Depreciation and amortization | $ 200,000 | $ 200,000 |
Other Property And Equipment [Member] | Minimum [Member] | ||
Significant Accounting Policies [Line Items] | ||
Estimated useful life | 3 years | |
Other Property And Equipment [Member] | Maximum [Member] | ||
Significant Accounting Policies [Line Items] | ||
Estimated useful life | 25 years |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2014 | Jun. 30, 2013 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | $ 1,759,461 | $ 1,550,438 | ||
Less provision for doubtful debts | (75,000) | |||
Accounts receivable, allowance for doubtful accounts | 75,000 | |||
Oil And Natural Gas Sales Related Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | 1,005,217 | 894,523 | ||
Cost Recovery From JV Partner Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | 734,912 | 572,082 | ||
Other Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | $ 94,332 | $ 83,833 |
Summary Of Significant Accoun_6
Summary Of Significant Accounting Policies (Schedule Of Oil And Gas Properties And Equipment) (Details) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 |
Summary Of Significant Accounting Policies [Abstract] | ||
Proved properties | $ 13,181,514 | $ 13,114,851 |
Lease and well equipment | 1,169,856 | 1,140,310 |
Less accumulated depreciation, depletion and impairment | (12,606,419) | (12,440,389) |
Total oil and gas properties and equipment | 1,744,951 | 1,814,772 |
Assets Held-for-sale, Not Part of Disposal Group, Current | $ 28,675,890 | |
Undeveloped capitalized acreage | $ 271,078 |
Summary Of Significant Accoun_7
Summary Of Significant Accounting Policies (Schedule Of Other Property And Equipment) (Details) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 |
Summary Of Significant Accounting Policies [Abstract] | ||
Furniture, fittings and equipment | $ 1,017,879 | $ 990,022 |
Less accumulated depreciation | (775,057) | (693,945) |
Total other property and equipment | $ 242,822 | $ 296,077 |
Summary Of Significant Accoun_8
Summary Of Significant Accounting Policies (Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities) (Details) - shares | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Diluted weighted average common shares outstanding | 3,283,000,444 | 3,257,194,847 |
Options And Warrants [Member] | ||
Anit-dilutive weighted average common shares outstanding | 314,500,000 | 287,956,323 |
Discontinued Operations (Schedu
Discontinued Operations (Schedule Of Earnings From Discontinued Operations, Net Of Income Tax) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Earnings from discontinued operations, net of income taxes | $ 743,696 | $ (1,094,034) |
Cashflows from Operating Activities | 6,768,727 | 2,236,620 |
Cashflows from Investing Activities | (445,997) | (2,718,371) |
Cashflows from Financing Activities | (1,350,391) | |
Discontinued Operations [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Lease operating expense | (6,031,983) | (7,751,072) |
Depletion, amortization and impairment | (1,071,959) | (1,770,500) |
Accretion of asset retirement obligations | (216,229) | (263,964) |
Amortization of borrowing costs | (440,434) | (219,810) |
Interest expense | (1,275,137) | (1,592,802) |
Earnings from discontinued operations, net of income taxes | (743,696) | 1,094,034 |
Cashflows from Operating Activities | 6,768,727 | 2,236,620 |
Cashflows from Investing Activities | (445,997) | (2,718,371) |
Cashflows from Financing Activities | (1,350,391) | |
Oil [Member] | Discontinued Operations [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Sales | 9,678,832 | 10,336,307 |
Natural Gas [Member] | Discontinued Operations [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Sales | 91,742 | 162,546 |
Other Liquids [Member] | Discontinued Operations [Member] | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Sales | $ 8,864 | $ 5,261 |
Hedging And Derivative Financ_3
Hedging And Derivative Financial Instruments (Narrative) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Hedging And Derivative Financial Instruments [Abstract] | ||
Fair value of derivative instruments | $ 99,603 | |
Derivative Liability, Current | $ 1,210,795 | 363,960 |
Loss on Derivative Instruments, Pretax | $ 2,722,166 | |
Gain on derivative instruments | $ 1,297,472 |
Hedging And Derivative Financ_4
Hedging And Derivative Financial Instruments (Schedule Of Open Derivative Contracts) (Details) | 3 Months Ended |
Sep. 30, 2016bbl / MMBTU$ / bbl | |
Derivative Contract Seven [Member] | |
Derivative [Line Items] | |
Derivative inception | Jul. 1, 2018 |
Derivative maturity | Dec. 31, 2018 |
Volume (BO/Mmbtu) | bbl / MMBTU | 80,960 |
Floor price | 45 |
Ceiling price | 56 |
Derivative Contract Eight [Member] | |
Derivative [Line Items] | |
Derivative inception | May 1, 2018 |
Derivative maturity | Dec. 31, 2018 |
Volume (BO/Mmbtu) | bbl / MMBTU | 50,490 |
Floor price | 2.65 |
Ceiling price | 2.90 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis) (Details) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | $ 1,376,676 | $ 628,778 | |
Non Current Assets, Derivative Instruments | 99,603 | ||
Current Liabilities, Derivative Instruments | 1,210,795 | 363,960 | |
Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | 1,376,676 | 628,778 | |
Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | |||
Current Assets, Derivative Instruments | 4,218 | 167,307 | |
Non Current Assets, Derivative Instruments | 370,494 | ||
Current Liabilities, Derivative Instruments | 1,215,013 | 531,267 | |
Non Current Liabilities, Derivative Instruments | 270,891 | ||
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] | (4,218) | (167,307) |
Non Current Assets, Derivative Instruments | [1] | (270,891) | |
Current Liabilities, Derivative Instruments | [1] | $ (4,218) | (167,307) |
Non Current Liabilities, Derivative Instruments | [1] | $ (270,891) | |
[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 (D
Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Asset Retirement Obligations [Line Items] | ||
Asset retirement obligations at beginning of period | $ 3,456,236 | $ 3,750,245 |
Liabilities incurred or acquired | 226,123 | |
Liabilities settled | 73,667 | 427,214 |
Disposition of properties | (73,011) | (409,683) |
Accretion expense | 34,554 | 316,765 |
Asset retirement obligations at end of period | 3,344,112 | 3,456,236 |
Less: current asset retirement obligation (classified with accounts payable and accrued liabilities) | (300,000) | |
Less current asset retirement obligatons related to assets held for sale | 2,509,981 | |
Long-term asset retirement obligations | $ 834,131 | $ 3,156,236 |
Minimum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Asset Retirement Obligations, Discount Rate | 4.00% | |
Maximum [Member] | ||
Asset Retirement Obligations [Line Items] | ||
Asset Retirement Obligations, Discount Rate | 13.00% |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) | 12 Months Ended | ||||
Jun. 30, 2018USD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2017AUD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2016USD ($) | |
Income Taxes [Line Items] | |||||
Tax losses carried forward | $ 15,509,399 | $ 15,949,783 | |||
Benefit of tax losses carried forward | 4,652,820 | $ 4,784,935 | |||
Net operating tax losses | $ 82,341,738 | ||||
Tax expense (benefit) | (732,056) | ||||
Internal Revenue Service (IRS) [Member] | |||||
Income Taxes [Line Items] | |||||
Net operating tax losses | 84,932,621 | ||||
Limitation per year | $ 403,194 | ||||
State and Local Jurisdiction [Member] | |||||
Income Taxes [Line Items] | |||||
Net operating tax losses | $ 49,189,363 | $ 47,582,073 | |||
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 | Jun. 1, 2015 | ||||
Maximum [Member] | Internal Revenue Service (IRS) [Member] | |||||
Income Taxes [Line Items] | |||||
Net operating losses, expiration year | Dec. 31, 2036 | ||||
Maximum [Member] | State and Local Jurisdiction [Member] | |||||
Income Taxes [Line Items] | |||||
Net operating losses, expiration year | Jun. 1, 2033 |
Income Taxes (Schedule Of Compo
Income Taxes (Schedule Of Components Of Income Tax Provision (Benefit)) (Details) | 12 Months Ended |
Jun. 30, 2018USD ($) | |
Income Taxes [Abstract] | |
Current Federal | $ (732,056) |
Current | (732,056) |
Deferred Federal | (732,056) |
Total income tax provision (benefit) | $ (1,464,112) |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income tax Rate Reconciliation) (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2014 | |
Income Taxes [Abstract] | |||
Federal statutory rate | 30.00% | ||
Income tax expense (benefit) at federal statutory rate | $ (1,956,277) | $ (787,563) | |
Effect of permanent differences and other - US | 115,616 | ||
State income taxes | (123,694) | (34,997) | |
Change in tax rate | 11,207,430 | ||
US income taxed at a different rate | 116,777 | ||
Foreign exchange | 282,557 | ||
Other adjustments - true up deferred balances | (10,819) | ||
Other - change in deferred tax rate | (239,200) | ||
Other | 23,507 | 112,867 | |
Valuation allowance | (10,387,153) | 948,893 | |
Income Tax Expense (Benefit), Total | $ (732,056) |
Income Taxes (Schedule Of Com_2
Income Taxes (Schedule Of Components Of Deferred Tax Assets and (Liabilities)) (Details) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 |
Income Taxes [Abstract] | ||
Net operating losses | $ 23,674,591 | $ 34,581,318 |
Asset retirement obligation | 737,875 | 1,212,151 |
Annual leave | 51,837 | 81,130 |
Abandonment limitation | 554,685 | 554,685 |
Allowance for doubtful debts | 17,560 | |
Accrued bonus | ||
Charitable contributions | 882 | |
AMT Credit | 780,443 | 780,443 |
Share based compensation | 500,844 | 500,844 |
Derivative liability | 283,458 | 98,175 |
Valuation allowance | (23,951,026) | (34,286,029) |
Commodity liability | ||
Amortization - loan costs | ||
Oil and gas property | (1,908,395) | (3,523,599) |
Net deferred income tax assets (liabilities) | 732,506 | |
Noncurrent deferred tax liability | $ 732,056 |
Income Taxes (Summary Of Valuat
Income Taxes (Summary Of Valuation Allowance) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Valuation Allowance [Line Items] | ||
Balance | $ 34,286,029 | |
Balance | 23,951,026 | $ 34,286,029 |
Deferred Income Tax [Member] | ||
Valuation Allowance [Line Items] | ||
Balance | 34,286,029 | 33,337,136 |
Additions (reductions) to deferred income tax expense | (10,387,153) | 948,893 |
Balance | $ 23,898,876 | $ 34,286,029 |
Capital Stock Contributed Equ_3
Capital Stock Contributed Equity (Narrative) (Details) | 12 Months Ended | |||
Jun. 30, 2018shares | Jun. 30, 2017$ / sharesshares | Jun. 30, 2017$ / sharesshares | Jun. 30, 2015AUD ($) | |
Shares issued upon exercise of options, shares | 140,143 | 140,143 | 140,143 | |
Weighted average exercise price - cents (AUD), exercised | (per share) | $ 0.038 | $ 3.800 | ||
Aggregate intrinsic value of options exercised | $ | $ 4,747 | |||
1.5 Cents [Member] | ||||
Shares issued upon exercise of options, shares | 140,143 | 140,143 |
Capital Stock Contributed Equ_4
Capital Stock Contributed Equity (Contributed Equity) (Details) - USD ($) | Jun. 30, 2018 | Jun. 30, 2017 |
Capital Stock Contributed Equity [Abstract] | ||
2,837,756,933 ordinary fully paid shares including shares to be issued (2013 - 2,229,165,163 ordinary fully paid shares including shares to be issued) | $ 106,743,167 | $ 106,390,864 |
Common stock outstanding and to be issued | 3,283,000,444 | 3,283,000,444 |
Capital Stock Contributed Equ_5
Capital Stock Contributed Equity (Movements In Contributed Equity For The Year) (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2016 | |
Beginning Balance, shares | 3,283,000,444 | 3,215,854,701 | |
Opening balance, value | $ 106,390,864 | $ 105,719,184 | |
Shares issued upon exercise of options, shares | 140,143 | 140,143 | |
Shares issued upon exercise of options, value | $ 4,516 | ||
Stock based compensation (options issued), value | 711,493 | ||
Transaction costs incurred, value | $ (44,329) | $ (44,329) | |
Ending Balance, shares | 3,283,000,444 | 3,283,000,444 | 3,215,854,701 |
Shares on issue at balance date, value | $ 106,743,167 | $ 106,390,864 | $ 105,719,184 |
Issued Capital [Member] | |||
Share based payment, shares | 67,005,600 | ||
Share based payment, value | $ 159,506 | ||
Stock based compensation (options issued), value | 711,493 | ||
Transaction costs incurred, value | $ (44,329) | ||
Warrant [Member] | |||
Share based payment, value | $ 352,303 | $ 551,987 |
Cash Flow Statement (Details)
Cash Flow Statement (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash Flow Statement [Abstract] | ||
Net loss after tax | $ (6,038,866) | $ (2,767,496) |
Net loss after tax | (6,038,866) | (2,767,496) |
Net (gain)/loss recognized on re-measurement to fair-value of investments held for trading | 946,438 | (2,640,373) |
Depreciation | 1,237,989 | 1,989,135 |
Accretion of asset retirement obligations | 250,783 | 316,765 |
Share Based payments and options issued | 352,303 | 711,493 |
Borrowing costs | 440,434 | 219,810 |
Exploration expense | 325,304 | 78,391 |
Impairment losses of oil and gas properties | 244,480 | |
Abandonment expense | 128,862 | 3,055 |
Gain on sale of assets | (178,407) | (2,250,070) |
Provision for doubtful debts | 75,000 | |
Income tax benefit | (732,056) | |
Non cash other income | (126,265) | |
(Increase)/decrease in receivables | (121,193) | 743,041 |
Increase/(decrease) in employee benefits | 1,766 | 54,563 |
Increase/(decrease) in payables | 5,746,229 | 815,566 |
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ 2,305,724 | $ (2,610,960) |
Credit Facility (Narrative) (De
Credit Facility (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||
Sep. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2018 | Jun. 30, 2015 | Jan. 31, 2014 | |
Credit Facility [Abstract] | ||||||
Line of credit facility, maximum borrowing capacity | $ 25,000,000 | |||||
Line of credit facility, current borrowing capacity | $ 24,000,000 | |||||
Line of credit facility, amount outstanding | 23,419,749 | $ 23,419,749 | $ 23,867,557 | $ 30,500,000 | ||
Line of credity facility, cap on general and administrative expenditure | 3,000,000 | $ 6 | ||||
Minimum hedging | $ 75 | 75 | ||||
Equity to be raised | $ 5 | 5,000,000 | ||||
Debt paydown required | $ 11,500,000 | $ 10,000,000 |
Credit Facility (Schedule of Cr
Credit Facility (Schedule of Credit Facilities) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Credit Facility [Abstract] | ||
Credit facility at beginning of period | $ 23,419,749 | $ 23,419,749 |
Cash advanced under facility | 450,000 | |
Assumption of promissory note | 4,000,000 | |
Repayments | (2,192) | (11,080,251) |
Credit facility at end of period | 23,867,557 | 23,419,749 |
Funds available for drawdown under the facility | $ 580,251 |
Share-Based Payments (Narrative
Share-Based Payments (Narrative) (Details) | 12 Months Ended | ||||
Jun. 30, 2018shares | Jun. 30, 2017$ / sharesshares | Jun. 30, 2017$ / sharesshares | Jun. 30, 2015AUD ($) | Jun. 30, 2015USD ($) | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exchange rate | 0.7692 | 0.7680 | 0.7680 | ||
Options granted | 320,000,000 | 320,000,000 | |||
Exercise price (Australian cents) | (per share) | $ 0.038 | $ 3.800 | |||
Options exercised | 140,143 | 140,143 | 140,143 | ||
Unrecognized compensation cost related to stock options | $ | $ 0.400 | ||||
Aggregate intrinsic value of options exercised | $ | $ 4,747 | ||||
1.5 Cents [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Options exercised | 140,143 | 140,143 |
Share-Based Payments (Schedule
Share-Based Payments (Schedule Of Assumption Used In Black-Scholes Model) (Details) - 12 months ended Jun. 30, 2017 | $ / shares | $ / shares |
Share-Based Payments [Abstract] | ||
Exercise price (Australian cents) | (per share) | $ 0.038 | $ 3.800 |
Share-Based Payments (Summary O
Share-Based Payments (Summary Of Stock Option Activity) (Details) | 12 Months Ended | ||
Jun. 30, 2018$ / sharesshares | Jun. 30, 2017$ / sharesshares | Jun. 30, 2017$ / sharesshares | |
Share-Based Payments [Abstract] | |||
Outstanding, start of period | 411,033,246 | 320,615,486 | 320,615,486 |
Granted | 320,000,000 | 320,000,000 | |
Exercised | (140,143) | (140,143) | (140,143) |
Cancelled/expired | (96,533,246) | (229,442,097) | (229,442,097) |
Outstanding, end of period | 314,500,000 | 411,033,246 | 411,033,246 |
Exercisable, end of period | 314,500,000 | 91,033,246 | 91,033,246 |
Weighted average exercise price - cents (AUD), outstanding, start of period | $ / shares | $ 1.180 | $ 4.600 | |
Weighted average exercise price - cents (AUD), granted | $ / shares | 0.570 | ||
Weighted average exercise price - cents (AUD), exercised | (per share) | 0.038 | $ 3.800 | |
Weighted average exercise price - cents (AUD), cancelled/expired | $ / shares | 3.800 | 3.800 | |
Weighted average exercise price - cents (AUD), outstanding, end of period | $ / shares | 0.5700 | 1.180 | |
Weighted average exercise price - cents (AUD), exercisable, end of period | $ / shares | $ 0.5700 | $ 3.800 |
Share-Based Payments (Schedul_2
Share-Based Payments (Schedule Of Additional Information Related To Options Outstanding) (Details) | 12 Months Ended | ||||
Jun. 30, 2017$ / sharesshares | Jun. 30, 2017$ / shares$ / sharesshares | Jun. 30, 2016$ / sharesshares | Jun. 30, 2013$ / shares | Jun. 30, 2018$ / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price (Australian cents) | (per share) | $ 0.038 | $ 3.800 | |||
Options outstanding, number outstanding | shares | 411,033,246 | 411,033,246 | 320,615,486 | 314,500,000 | |
Options outstanding, weighted average exercise prices | $ 1.180 | $ 1.180 | $ 4.600 | $ 0.5700 | |
Options exercisable, number exercisable | shares | 91,033,246 | 91,033,246 | 314,500,000 | ||
Options exercisable, weighted average exercise prices | $ 3.800 | $ 3.800 | $ 0.5700 | ||
3.9 Cents [Member] | |||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||
Exercise price (Australian cents) | $ 0.0055 | ||||
Options outstanding, number outstanding | shares | 266,500,000 | ||||
Options outstanding, weighted average remaining contractual life - years | 8 years 5 months 1 day | ||||
Options outstanding, weighted average exercise prices | $ 0.0055 |
Commitments (Narrative) (Detail
Commitments (Narrative) (Details) - USD ($) | 12 Months Ended | |||||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2017 | Jun. 30, 2014 | |
Commitments [Abstract] | ||||||
Operating leases, 2018 | $ 123,873 | $ 123,873 | ||||
Operating leases, 2019 | $ 127,845 | 127,845 | ||||
Operating leases, 2020 | 131,309 | |||||
Operating Leases, 2021 | 8,947 | |||||
Operating Leases, 2022 | ||||||
Operating leases, Thereafter | ||||||
Net rent expense | $ 214,650 | $ 153,375 |
Commitments (Contractual Obliga
Commitments (Contractual Obligations) (Details) - USD ($) | Jun. 30, 2020 | Jun. 30, 2019 | Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2014 |
Commitments [Abstract] | ||||||
Asset retirement obligations, Total | $ 3,344,112 | $ 3,456,236 | $ 3,750,245 | |||
Operating leases, Total | 391,974 | |||||
Operating leases, 2018 | $ 123,873 | 123,873 | ||||
Operating leases, 2019 | $ 127,845 | 127,845 | ||||
Operating leases, 2020 | 131,309 | |||||
Operating leases, 2021 | 8,947 | |||||
Operating leases, 2022 | ||||||
Operating leases, Thereafter |
Contingencies (Details)
Contingencies (Details) | Jun. 30, 2013USD ($) |
Contingencies [Abstract] | |
Contingent assets | |
Contingent liabilities |
Supplemental Information On O_3
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Narrative) (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2014 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | |||
12 month historical average price per Mcf | $ 2.95 | $ 3.01 | |
12 month historical average price per barrel of oil | $ 57.67 | $ 48.95 | |
Discount factor of future net cash flows | 10.00% |
Supplemental Information On O_4
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, 2018 | Jun. 30, 2017 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | ||
Development costs | $ 13,272 | $ 2,458,276 |
Exploration costs | 68,865 | |
Undeveloped capitalized acreage | 50,375 | |
Total costs incurred | $ 82,137 | $ 2,508,651 |
Supplemental Information On O_5
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, 2018MBoeMBblsMMcf | Jun. 30, 2017MBoeMBblsMMcf | |
Reserve Quantities [Line Items] | ||
Proved Developed Reserves ProductionBOE | MBoe | (195) | (323) |
Beginning of year (BOE) | MBoe | 5,955 | 11,415 |
Revisions of previous quantity estimates (BOE) | MBoe | (2,028) | (3,263) |
Sales of reserves in place (BOE) | MBoe | (1,874) | |
End of year (BOE) | MBoe | 3,732 | 5,955 |
Proved developed producing reserves (BOE) | MBoe | 84 | 3,285 |
Proved undeveloped reserves (BOE) | MBoe | 350 | 2,499 |
Proved Developed Non Producing (BOE) | MBoe | 39 | 171 |
Proved developed producing reserves - held for sale (BOE) | MBoe | 2,685 | |
Proved developed non producing - held for sale (BOE) | MBoe | 575 | |
Proved reserves (BOE) | MBoe | 3,732 | 5,955 |
Oil [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of year (Volume) | MBbls | 5,359 | 9,982 |
Revisions of previous quantity estimates (Volume) | MBbls | (1,654) | (2,851) |
Sales of reserves in place (Volume) | MBbls | (1,475) | |
Production (Volume) | MBbls | (190) | (297) |
End of year (Volume) | MBbls | 3,515 | 5,359 |
Proved developed producing reserves (Volume) | MBbls | 73 | 3,020 |
Proved Developed Non Producing (Volume) | MBbls | 32 | 134 |
Proved undeveloped reserves (Volume) | MBbls | 308 | 2,205 |
Proved developed producing reserves - held for sale (Volume) | MBbls | 2,590 | |
Proved developed non producing - held for sale (Volume) | MBbls | 512 | |
Proved reserves (Volume) | MBbls | 3,515 | 5,359 |
Natural Gas [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of year (Volume) | MMcf | 3,565 | 8,593 |
Revisions of previous quantity estimates (Volume) | MMcf | (2,246) | (2,474) |
Sales of reserves in place (Volume) | MMcf | (2,396) | |
Production (Volume) | MMcf | (27) | (158) |
End of year (Volume) | MMcf | 1,292 | 3,565 |
Proved developed producing reserves (Volume) | MMcf | 60 | 1,575 |
Proved Developed Non Producing (Volume) | MMcf | 43 | 224 |
Proved undeveloped reserves (Volume) | MMcf | 251 | 1,766 |
Proved developed producing reserves - held for sale (Volume) | MMcf | 563 | |
Proved developed non producing - held for sale (Volume) | MMcf | 375 | |
Proved reserves (Volume) | MMcf | 1,292 | 3,565 |
Supplemental Information On O_6
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, 2018 | Jun. 30, 2017 | Jun. 30, 2016 |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | |||
Future cash inflows | $ 187,249 | $ 237,490 | |
Future production costs | (99,620) | (91,920) | |
Future development costs | (1,642) | (13,367) | |
Future net cashflows | 85,987 | 132,203 | |
10% discount | (38,325) | (66,941) | |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | $ 47,662 | $ 65,262 | $ 66,747 |
Supplemental Information On O_7
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, 2018 | Jun. 30, 2017 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | ||
Beginning of year | $ 65,262 | $ 66,747 |
Sales of oil and gas produced during the period, net of production costs | (3,902) | (3,122) |
Net changes in prices and production costs | 2,822 | 1,601 |
Changes in estimates of future development costs | (11,625) | 22,929 |
Revisions of previous quantity estimates and other | (10,088) | (21,078) |
Sale of reserves in place | (10,445) | |
Accretion of discount | 6,526 | 6,675 |
Other | (1,333) | 1,955 |
Balance at end of year | $ 47,662 | $ 65,262 |