Document And Entity Information
Document And Entity Information - USD ($) $ in Thousands | 12 Months Ended | ||
Jun. 30, 2016 | Sep. 26, 2016 | Dec. 31, 2015 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Jun. 30, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
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 | 3,215,854,791 | ||
Entity Public Float | $ 5,200 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 2,654,812 | $ 2,062,720 |
Accounts receivable, net of allowance for doubtful accounts of $nil and $nil respectively | 1,996,415 | 3,645,223 |
Energy Related Inventory, Crude Oil and Natural Gas Liquids | 463,768 | |
Prepayments | 183,305 | 372,079 |
Fair value of derivative instruments | 159,216 | |
Assets Held-for-sale, Not Part of Disposal Group, Current | 13,768,865 | |
Total current assets | 19,067,165 | 6,239,238 |
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 | 31,522,323 | 29,715,540 |
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 | 308,474 | 248,521 |
Net property, plant and equipment | 31,830,797 | 29,964,061 |
OTHER ASSETS | ||
Undeveloped capitalized acreage | 220,703 | 2,491,422 |
Capitalized exploration expense | 1,388,798 | |
Fair value of derivative instruments | 101,269 | |
Malpractice Loss Contingency, Letters of Credit and Surety Bonds | 450,000 | |
Other | 474,325 | 342,069 |
TOTAL ASSETS | 52,042,990 | 40,526,857 |
CURRENT LIABILITIES | ||
Accounts payable | 4,125,643 | 1,678,915 |
Accrued liabilities | 1,629,975 | 1,999,344 |
Provision for annual leave | 194,497 | 219,414 |
Fair value of derivative instruments | 1,671,653 | |
Short-term Debt | 4,046,428 | |
Short term repayment of long term debt | 11,500,000 | |
Total current liabilities | 23,168,196 | 3,897,673 |
Fair value of derivative instruments | 1,233,076 | |
Asset retirement obligations | 3,450,245 | 1,263,674 |
Credit Facility | 19,000,000 | 18,699,000 |
Total liabilities | 46,851,517 | 23,860,347 |
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) | 105,719,184 | 104,491,774 |
Other comprehensive income | 927,718 | 996,256 |
Retained earnings (accumulated deficit) | (101,455,429) | (88,821,520) |
Total stockholders' equity | 5,191,473 | 16,666,510 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 52,042,990 | $ 40,526,857 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2013 |
Consolidated Balance Sheets [Abstract] | ||||
Accounts receivable, allowance for doubtful accounts | ||||
Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion Amortization and Impairment | $ 15,049,015 | $ 44,273,976 | ||
Other property and equipment, accumulated depreciation and amortization | $ 573,995 | $ 553,428 | ||
Common stock, par value | ||||
Common stock, shares issued | 3,215,854,701 | 2,837,782,022 | ||
Common stock, shares outstanding | 2,837,782,022 | 3,215,854,701 |
Consolidated Statements Of Oper
Consolidated Statements Of Operations - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
REVENUES AND OTHER INCOME: | ||
Interest income | $ 2,569 | $ 30,759 |
Gain on derivative instruments | 3,112,268 | |
Business Combination, Bargain Purchase, Gain Recognized, Amount | 10,775,231 | |
Other | 897,448 | 137,857 |
TOTAL REVENUE AND OTHER INCOME | 20,677,603 | 16,575,890 |
EXPENSES: | ||
Lease operating expense | (5,427,752) | (6,117,217) |
Depletion, depreciation and amortization | (4,766,949) | (6,920,945) |
Impairment of oil and natural gas properties | (11,029,442) | (21,475,450) |
Exploration and evaluation expenditure | (4,216,077) | (12,686,943) |
Accretion of asset retirement obligations | (125,078) | (40,159) |
General and administrative | (3,685,673) | (4,812,668) |
Abandonment Expense | (404,485) | |
Loss on derivative instruments | (2,657,963) | |
Borrowing costs | (185,138) | (135,694) |
Interest expense | (1,217,440) | (598,940) |
TOTAL EXPENSES | (33,311,512) | (53,192,501) |
Loss before income tax | (12,633,909) | (36,616,611) |
Income tax (provision)/benefit | (3,021) | |
Net loss | (12,633,909) | (36,619,632) |
OTHER COMPREHENSIVE LOSS | ||
Foreign currency translation | (68,538) | (305,840) |
Total comprehensive loss for the period | $ (12,702,447) | $ (36,925,472) |
Net earnings per common share from continuing operations: | ||
Basic loss per common share - cents per share | $ (0.43) | $ (1.29) |
Diluted earnings per common share - cents per share | $ (0.43) | $ (1.29) |
Weighted average common shares outstanding: | ||
Basic | 2,919,426,154 | 2,837,777,322 |
Diluted | 2,919,426,154 | 2,837,777,322 |
Oil [Member] | ||
REVENUES AND OTHER INCOME: | ||
Sales revenue | $ 8,240,529 | $ 12,460,171 |
Natural Gas [Member] | ||
REVENUES AND OTHER INCOME: | ||
Sales revenue | 714,103 | $ 834,835 |
Other Liquids [Member] | ||
REVENUES AND OTHER INCOME: | ||
Sales revenue | $ 47,723 |
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, 2014 | $ 104,535,894 | $ (52,201,888) | $ 1,302,096 | $ 53,636,102 |
Net loss | (36,619,632) | (36,619,632) | ||
Foreign currency translation | (305,840) | (305,840) | ||
Total comprehensive loss for the period | (36,619,632) | (305,840) | (36,925,472) | |
Issue of share capital | 880 | 880 | ||
Share issue costs | (45,000) | (45,000) | ||
Ending Balance, value at Jun. 30, 2015 | 104,491,774 | (88,821,520) | 996,256 | 16,666,510 |
Net loss | (12,633,909) | (12,633,909) | ||
Foreign currency translation | (68,538) | (68,538) | ||
Total comprehensive loss for the period | (12,633,909) | (68,538) | (12,702,447) | |
Issue of share capital | 1,400,150 | 1,400,150 | ||
Share issue costs | (172,740) | (172,740) | ||
Ending Balance, value at Jun. 30, 2016 | $ 105,719,184 | $ (101,455,429) | $ 927,718 | $ 5,191,473 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Cash flows from operating activities | ||
Receipts from customers | $ 10,443,411 | $ 13,177,704 |
Cash received from commodity derivative financial instruments | 637,980 | 2,275,026 |
Payments to suppliers & employees | (9,015,060) | (11,172,887) |
Interest received | 2,573 | 31,061 |
Interest paid | (808,144) | (481,714) |
Income taxes paid | (107,135) | |
Payments for abandonment costs | (53,783) | (677,616) |
Proceeds from Legal Settlements | 725,000 | |
Net Cash Provided by (Used in) Operating Activities, Continuing Operations, Total | 1,931,977 | 3,044,439 |
Cash flows from investing activities | ||
Proceeds from sale of oil and gas properties | 1,000,000 | |
Payments for operating bonds | (450,000) | |
Payments for plant & equipment | (183,266) | (20,249) |
Payments for exploration and evaluation | (749,731) | (2,406,192) |
Payments of business combination | (16,089,029) | |
Payments for oil and gas properties | (1,531,407) | (17,670,628) |
Net cash flows (used in)/ provided by investing activities | (18,003,433) | (20,097,069) |
Cash flows from financing activities | ||
Proceeds from issue of share capital | 1,400,150 | 880 |
Proceeds from borrowings | 11,801,000 | 13,000,000 |
Proceeds from short term borrowings | 4,000,000 | |
Repayment of borrowings | (301,000) | |
Payments for costs associated with borrowings | (295,151) | (83,690) |
Payments for costs associated with capital raising | (172,740) | (45,000) |
Net cash flows (used in)/ provided by financing activities | 16,733,259 | 12,571,190 |
Net (decrease)/increase in cash and cash equivalents | 661,803 | (4,481,440) |
Cash and cash equivalents at the beginning of the year | 2,062,720 | 6,846,394 |
Effects of exchange rate changes on cash and cash equivalents | (69,711) | (302,234) |
Cash and cash equivalents at end of year | $ 2,654,812 | $ 2,062,720 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Jun. 30, 2016 | |
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, Montana and Wyoming. 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. All 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, 201 6 or 201 5 . 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 2016 2015 Oil and natural gas sales $ 1,717,110 $ 3,224,595 Cost recovery from drilling partners 275,018 275,148 Other 4,287 145,480 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015 $ 1,996,415 $ 3,645,223 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. The cost recovery from drilling partners relates to the partners share of drilling costs associated with the current drilling program in our North Stockyard infill project and Hawk Springs project. Accruals. The components of accrued liabilities for the years ended June 30, 201 6 and 201 5 are as follows: 2016 2015 Bonus accrual - - Other accruals 629,975 1,999,344 Deposit received for asset sale 1,000,000 0 $ 1,629,975 $ 1,999,344 Other accruals includes an estimate of the costs expected to be incurred with respect to the asset retirement obligation in the next twelve months. The deposit received from the asset sale is non-refundable (subject to the identification of certain title or environmental defects for the deadline for providing notification to the Company has passed) deposit received from the purchaser of our North Stockyard assets. The majority of other accruals in the prior year relate to expenses incurred in relation to our exploratory well, Bluff, in our Hawk Springs project and other general accruals. Oil and Gas Properties. Oil and gas properties and equipment consist of the following at June 30: 2016 2015 Proved properties $ 45,177,047 $ 61,724,561 Lease and well equipment 1,394,291 12,264,955 Less accumulated depreciation, depletion and impairment (15,049,015) (44,273,976) $ 31,522,323 $ 29,715,540 Assets held for sale 13,768,865 - Unproved acreage $ 220,703 $ 2,491,422 Capitalized exploration expense $ - $ 1,388,798 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 consider s numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term . Assets held for sale On June 30, 2016, the Company signed a Purchase and Sale Agreement for the sale of its interests in the North Stockyard field. The purchase price of the acquisition is $15 million and the acquisition is expected to settle on October 20, 2016. The effective date of the acquisition is the day after the closing date. The Company received a $1 million deposit from the purchaser on the date of signing, recorded in current liabilities. This deposit is only refundable if certain title or environmental defects are identified during the purchasers due diligence. The date by which the purchaser was required to notify the Company of any title or environmental defects has passed and the Company was not advised of any environmental or title defects. 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 conclude s that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement. During the fiscal year ended June 30, 2016, we expensed $4.2 million in deferred exploration expense in relation to our Hawk Springs project area. During the fiscal year ended June 30, 2015 the Company expensed $8.1 million in relation to our Roosevelt project in Montana. During the year ended June 30, 2014 the Company entered into a farm out arrangement with respect to this property however due to the falling oil prices, the farm out partner failed to meet it’s obligations under the agreement. The Company do es not plan to spend any additional capital in this project area and therefore we have written off the previously capitalized exploration expenditure. The Company also wrote off $2.5 million with respect to its South Prairie project in North Dakota. A second dry hole was drilled in the area during the year ended June 30, 2015 and the decision was made to write off the costs capitalized with respect to this project. The Company also expensed $ 1.6 million with respect to its Hawk Springs project in Wyoming. These costs were associated with leases expiring during the year. The Company also expensed $0.4 million of general exploration expenditure, which was never capitalized to the Balance Sheet. Impairment The Company recorded impairment charges of $ 11.0 million and $ 21.5 million for the years ended June 30, 201 6 and 201 5 respectively. The charges in the fiscal year ended June 30, 2016 related to the impact of the drop in the oil price on our North Stockyard, Rainbow and State GC project areas. The charges in the fiscal year ended June 30, 2015 related to the impact of the drop in the oil price on our Rainbow and North Stockyard projects in North Dakota. 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, 201 6 a nd 201 5 was $0.1 million and $ 0.1 million, respectively. Other property and equipment consists of the following at June 30: 2016 2015 Furniture, fittings and equipment $ 882,469 $ 801,949 Less accumulated depreciation (573,995) (553,428) $ 308,474 $ 248,521 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, 2016 2015 Dilutive - - Anti–dilutive 321,955,194 357,099,676 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 Australia n dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S dollars. The pres entation currency of the Consolidated Entity is U.S. dollars. Transactions in foreign currencies are initially recorded in the functional currency by applying the exchange rates ruling at the date of the transaction. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year ended exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in profit and loss Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. Translation differences on non-monetary assets and liabilities are recognized in other comprehensive income. Business Combinations Samson applies the acquisition method in accounting for business combinations. The consideration transferred by the Company is calculated as the sum of the acquisition date fair value of assets transferred, liabilities incurred and any equity interests issued by the Company, which includes the fair value of any asset or liability arising from any contingent consideration arrangements. Acquisition costs are expensed as incurred. The Company treats the acquisition of oil and gas assets as a business combination. The Company recognizes identifiable assets acquired and liabilities assumed in a business combination regardless of whether they have been previously recognized in the acquiree’s financial statements prior to the acquisition. Assets acquired and liabilities assumed are generally measured at their acquisition date fair values. If the fair values of identifiable net assets exceeds the sum calculated has the fair value transferred, the excess amount, a gain on bargain purchase) is recognized in the statement of operations immediately. In the current period, the Company recognized a gain on bargain purchase of $10.7 million with respect to its acquisition of certain producing and non producing assets, known as the Foreman Butte project. Impact of Recently Adopted Accounting Standards. There have been no recently adopted accounting standards that would impact our business. Recently Issued Accounting Pronouncements In August 2014, the FASB issued new guidance related to the disclosures around going concern. The new standard provides guidance around management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The new guidance becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. The adoption of this standard is not expected to have a material impact on the Company’s consolidated financial statements. 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 is currently evaluating the impact of this new standard; however, the Company does not expect adoption to have a material impact on its consolidated financial statements. In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends the existing accounting standards for revenue recognition. The standard requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The guidance in ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017, including interim periods therein, as a result of the FASB's recent decision to defer the effective date by one year. We are currently evaluating the method of adoption and impact this standard will have on our consolidated financial statements and related disclosures. |
Business Combination
Business Combination | 12 Months Ended |
Jun. 30, 2016 | |
Business Combination [Abstract] | |
Business Combination | 2. BUSINESS COMBINATION On March 31, 2016, the Company closed on the acquisition of producing and non producing wells in the Madison and Ratcliffe formations in North Dakota and Montana. The acquisition had an effective date of October 31, 2015 and closed on March 31, 2016. USD Amount Settled in Cash $ 1,391,874 Extension of credit facility 11,500,000 Fair value of promissory note provided 3,928,571 Fair value of consideration transferred 16,820,445 - Recognised amounts of identifiable assets and liabilities: Oil and gas properties 29,350,256 Oil inventory acquired 463,768 Trade receivables 53,540 Revenue in suspense assumed (403,612) Asset retirement obligation assumed (1,868,276) Net identifiable assets and liabilities 27,595,676 Gain on bargain purchase 10,775,231 Consideration Transferred The cost of the acquisition was settled in cash and the promissory note in the amount of $16.6 million (including post closing settlement payments). $1.2 million was settled from the Company’s cash reserves, $11.5 million came from an extension of the Company’s credit facility with Mutual of Omaha Bank and $3.9 million was provided by a promissory note provided to the seller of the assets. The fair value of the promissory note was determined to be $3.9 million on acquisition date based on an effective interest rate of 12% . The face value of the note is $4 million. The note accrues 10% interest per annum, and is due for repayment on April 1, 2017. The interest is payable in a balloon payment at maturity. The note is secured by a second lien over all the assets acquired. Identifiable net assets The assets, collectively known as the Foreman Butte acquisition, consist of interests in a number wells, both operated and non operated in the Madison and Ratcliffe formations in Montana and North Dakota. The fair value of the assets acquired was determined with reference to the reserve value of those assets at acquisition date, the Company’s cost of capital and other comparable transactions. The trade receivables, oil inventory and revenue in suspense were recognized at face value as this approximates fair value. The Company incurred acquisition costs of $0.2 million which have been expensed. Proforma Contribution to Results (unaudited) Contribution of Business Combination to Company Results The following represents the amount of the Company's revenue and losses for the years ended June 30, 2016 and June 30, 2015, assuming the business combination occurred on July 1, 2014. 2016 2015 Revenues $ 25,579,347 $ 19,849,812 Losses (15,762,744) (35,982,244) These results do not necessarily reflect the results that would have been incurred if the Company did own the assets as of July 1, 2014. |
Hedging And Derivative Financia
Hedging And Derivative Financial Instruments | 12 Months Ended |
Jun. 30, 2016 | |
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, 2016 , 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 . A s such no collateral is required by the counterparty. At June 30, 2016 the Company’s open derivative contracts consisted of the following: Collar Product Start Date End Date Volume (BO/Mmbtu) Floor Ceiling WTI 1-Jul-16 30-Apr-18 133,032 41.50 63.00 Henry Hub 1-Jul-16 31-Oct-16 127,229 1.90 2.40 Henry Hub 1-Nov-16 31-Mar-17 134,088 2.60 3.35 Henry Hub 1-Apr-17 31-Oct-17 167,682 2.40 2.91 Henry Hub 1-Nov-17 30-Apr-18 127,030 2.80 3.60 Fixed price swap Product Start End Volume (BO) Swap WTI 1-Jul-16 31-Dec-16 83,730 41.20 WTI 1-Jan-17 31-Dec-17 141,255 44.09 WTI 1-Jan-18 30-Apr-18 39,720 45.55 At June 30, 2015 the Company’s open derivative contracts consisted of the following: Oil Price Collars – WTI Volumes (bbls) Floor US$ Ceiling US$ January 2016 - February 2016 2,788 85.00 89.85 Oil Price Swaps – WTI Volumes (bbls) Price US$ July 2015 - December 2015 8,765 105.00 January 2016 - February 2016 2,788 105.00 Oil Price Three Way Swaps - WTI Volumes (bbls) Ceiling US$ Sub Floor US$ Floor US$ July 2015 - December 201 5 55,200 70.25 32.50 45.00 January 2016 - December 2016 27,450 80.00 40.00 55.00 January 2016 – December 2016 36,600 - 67.50 82.50 During the year ended June 30, 2016, the Company recognized $2.7 million in the Statement of Operations in loss in derivative instruments. As of June 30, 2016, the derivative instruments were valued at a unrealized loss of $2.8 million of which, $1.6 million is recorded as a current liability and $1.2 million is recorded as a non-current liability. During the year ended June 30, 2015, the Company recognized $3.1 million in the Statement of Operations in gain on derivative instruments. As of June 30, 2015, its derivative instruments were valued at $159,216 recorded as current asset and $101,269 recorded as a non-current asset. See Note 4 for additional fair value disclosures about the Company’s oil 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, 2016 | |
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, 201 6 and 201 5 . Fair Value at June 30, 2016 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 2,654,812 $ - $ - $ - $ 2,654,812 Derivative Instruments - 136,727 - (136,727) - Non Current Assets: Derivative Instruments - 220,317 - (220,317) - Current Liabilities Derivative Instruments - 1,808,380 - (136,727) 1,671,653 Non Current Liabilities: Derivative Instruments 1,453,393 (220,317) 1,233,076 Fair Value at June 30, 2015 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 2,062,720 $ - $ - $ - $ 2,062,720 Derivative Instruments - 379,540 - (220,324) 159,216 Non Current Assets: Derivative Instruments - 298,703 - (197,434) 101,269 Current Liabilities Derivative Instruments - 220,324 - (220,324) - Non Current Liabilities: Derivative Instruments 197,434 (197,434) - (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 , including the Foreman Butte acquistion , 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, 2016 | |
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, 201 6 and 201 5 : 2016 2015 Asset retirement obligations at beginning of period $ 1,810,674 $ 1,775,792 Liabilities incurred or acquired 1,868,276 672,339 Liabilities settled (53,783) (677,616) Disposition of properties - - Accretion expense 125,078 40,159 Asset retirement obligations at end of period 3,750,245 1,810,674 Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) (300,000) (547,000) Long-term asset retirement obligations $ 3,450,245 $ 1,263,674 Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 4 % and 1 3 %. The liabilities incurred in the current year relate to the liabilities acquired in relation to the Foreman Butte acquisition. |
Income Taxes
Income Taxes | 12 Months Ended |
Jun. 30, 2016 | |
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 2016 2015 Current: Federal $ - $ 2,821 State - 200 - 3,021 Deferred: Federal - - State - - Total income tax provision (benefit) $ - $ 3,021 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 2016 2015 Income tax expense (benefit) at federal statutory rate $ (3,790,398) $ (10,984,983) State income taxes (228,568) (472,583) Alternative minimum tax - 2,821 Other adjustments - true up of deferred balances (498,257) (1,101,884) Other - change in deferred tax rate (188,080) 60,666 Other (550,957) (1,562,773) Valuation allowance 5,256,260 14,061,757 $ - $ 3,021 The components of deferred tax assets and (liabilities) are as follows (in thousands): June 30 201 6 201 5 Deferred income tax assets: Net operating losses $ 33,548,583 $ 25,995,717 Asset retirement obligation 1,395,262 458,869 Annual leave 60,826 71,309 Abandonment limitation 446,543 145,000 Accrued bonus - 64,789 Charitable contributions 876 862 AMT credit 780,443 780,443 Share based compensation 500,844 500,844 Oil and Gas Property - 157,481 Derivative liability 1,071,109 - Valuation allowance (33,337,136) (28,080,876) Deferred income tax liabilities: Commodity liability - (94,588) Amortization - loan costs - - Oil and gas property (4,467,350) - Net deferred income tax assets (liabilities) - - Net current deferred tax asset - - Noncurrent deferred tax liability $ - $ - The following table summarizes the activities for the Company’s valuation allowance for the years ended: June 30 2016 2015 Deferred Income Tax Valuation Allowance Balance at July 1 28,080,876 14,019,119 Additions (reductions) to deferred income tax expense 5,256,260 14,061,757 Balance at June 30 33,337,136 28,080,876 The income tax expense recognized in the prior year is a result of a change in the estimated amount of AMT receivable from the IRS. The Company has tax losses carried forward arising in Australia of $ 15,621,491 (201 5 : $ 13,316,288 ). The benefit of these losses of $ 4,686,447 (201 5 : $3, 994,887 ) 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 $ 79,987,858 (201 5 : $ 61,688,535 ). The current year utilization carried back to prior years, is approximately $ nil (201 5 : $ 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. NOL’s 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 20 20 to 203 6 . In addition to the above mentioned Federal carried forward losses in the United States, the Company also has approximately $ 46,216,143 (201 5 : $ 29,217,044 ) 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. 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. A reconciliation of the beginning and ending amount of gross uncertain tax positions is as follows: 201 6 201 5 Total gross uncertain tax positions at beginning of year $ - $ 107,524 Additions / Reductions for tax positions of prior years - - Additions / Reductions for tax positions of current year - - Reductions due to settlements with taxing authorities - (107,524) Reductions due to lapse of statute of limitations - - Total amount of gross uncertain tax positions at end of year $ - $ - The State of North Dakota has made a claim against our wholly owned subsidiary, Samson Oil and Gas USA, Inc. relating to additional corporate income tax allegedly due for the years ended June 30, 2007 through June 30, 2011 in an amount of $597,852 . We have reached a settlement with the State of North Dakota for a payment of $107, 524, which was paid in July 2014. |
Capital Stock Contributed Equit
Capital Stock Contributed Equity | 12 Months Ended |
Jun. 30, 2016 | |
Capital Stock Contributed Equity [Abstract] | |
Capital Stock Contributed Equity | 7. COMMON STOCK Consolidated Entity 2016 2015 3,215,854,701 ordinary fully paid shares including shares to be issued $ 105,719,184 $ 104,491,774 (2015 – 2,837,782,022 ordinary fully paid shares including shares to be issued) Movements in contributed equity for the year 2016 2015 No. of shares $ No. of shares $ Opening balance 2,837,782,022 104,491,774 2,837,756,933 104,535,894 Capital raising (i) 378,020,400 1,398,675 - - Shares issued upon exercise of options (ii) 52,279 1,475 25,089 880 Stock based compensation (options issued) - - - - Transaction costs incurred - (172,740) - (45,000) Shares on issue at balance date 3,215,854,701 105,719,184 2,837,782,022 104,491,774 318,452,166 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) Equity raised during the fiscal year ended June 30, 2016 In April 2016, we issued 378,020,400 ordinary shares at a purchase price of $0.0036 per share to raise $1.4 million in a private placement to certain institutional investors. (ii) During the course of the year the Company issue d 5 2,279 (201 5 : 2 5,089 ) ordinary shares upon the exercise of 5 2 , 279 (201 5 : 2 5,089 ) options. The exercise price of 5 2 , 279 (201 5 : 2 5,089 ) of the options exercised was A$ 0.038 cents per share/US$ 0.0 28 cents per shares (average price based on the exchange rate on the date of exercise) (201 5 :A$ 0.038 /US$ 0.035 cents per share) to raise US$ 1,475 (201 5 : US$ 880 ) . |
Cash Flow Statement
Cash Flow Statement | 12 Months Ended |
Jun. 30, 2016 | |
Cash Flow Statement [Abstract] | |
Cash Flow Statement | 8. CASH FLOW STATEMENT Year ended June 30 2016 2015 A reconciliation of the net loss to the net cash provided by operations is as follows: Net loss after tax $ (12,633,909) $ (36,619,632) Depreciation 4,766,949 6,920,945 Accretion of asset retirement obligations 125,078 40,159 Exploration and evaluation expenditures 4,216,077 12,686,943 Impairment losses of oil and gas properties 11,029,442 21,475,450 Borrowing costs 185,138 135,694 Change in fair value of derivative instruments 2,644,244 (673,859) Bargain purchase on acquistion (10,775,231) - Abandonment costs - 404,485 Changes in assets and liabilities: Decrease in receivables 1,648,678 667,223 Decrease in employee benefits (24,917) (10,897) Increase/(decrease) in payables 750,428 (1,982,072) NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 1,931,977 $ 3,044,439 |
Credit Facility
Credit Facility | 12 Months Ended |
Jun. 30, 2016 | |
Credit Facility [Abstract] | |
Credit Facility | 9. CREDIT FACILITY June 30, 2016 2015 Credit facility at beginning of period $ 18,699,000 $ 6,000,000 Cash advanced under facility 11,801,000 13,000,000 Repayments - (301,000) Credit facility at end of period $ 30,500,000 $ 18,699,000 Less fund due for repayment in the next 12 months (11,500,000) - Total amount outstanding in long term credit facility $ 19,000,000 $ 18,699,000 Funds available for drawdown under the facility - - In March 2016, the facility was extended to $30.5 million to partly fund the Foreman Butte acquisition. 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) ; · 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 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 $ 30.5 million and is fully drawn as at September 28, 2016. We intend to repay $11.5 million of the facility from proceeds from the sale of our interest in the North Stockyard field. This sale is anticipated to close October 20, 2016. Should this sale not close as anticipated we will be required to ask Mutual of Omaha bank for an extension on the debt pay down. In January 2014, we entered into a $25.0 million credit facility with Mutual of Omaha Bank. The current borrowing base is $30.5 million , of which $30.5 million is drawn at June 30, 2016 . The next borrowing base redetermination is expected to be completed in October 201 6 based on June 30, 201 6 reserves information. The facility matures October 31, 2017 . Following the increase in the facility t he interest rate is LIBOR plus 6.00% or approximately 6.3% at June 30, 201 6 . All of our assets are pledged as collateral under this facility. As at June 30, 2016 we were in compliance with all of these quarterly covenants. We raised $1.4 million in equity, in April 2016, towards the total of $5.0 million of equity to be raised that is required under the facility by September 30, 2016. Mutual of Omaha Bank has agreed to extend this deadline to November 15, 2016. Mutual of Omaha Bank have also agreed to apply the excess proceeds over the $11.5 million required to be paid to Mutual of Omaha Bank to this total. We incurred $0. 4 million in borrowing costs which have been deferred and will expensed through the effective interest rate charge . |
Share-Based Payments
Share-Based Payments | 12 Months Ended |
Jun. 30, 2016 | |
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, 201 6 balances denominated in Australian dollars to U.S. dollars, we used the June 30, 201 6 and 201 5 Federal Reserve Bank of Australia (www.rba.gov.au) closing exchange rates of 0.768 and 0.942 . 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. No options were issued during the year ended June 30, 2016 as share based payments. No options were issued during the year ended June 30, 2015 as share based payments. As of June 30, 201 6 , there was US$ N il unrecognized compensation cost related to stock options. The following summarizes the Company’s stock option and warrant activity for the years ended June 30, 201 6 and 201 5 (all values in AUD unless otherwise noted): 2016 2015 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 324,667,765 0.038 389,192,854 0.046 Granted - - - - Exercised (52,279) 0.038 (25,089) 0.038 Cancelled/expired (4,000,000) 0.155 (64,500,000) 0.090 Outstanding, end of period 320,615,486 0.038 (0.03) 324,667,765 0.038 Exercisable, end of period 320,615,486 0.038 324,667,765 0.038 (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. All warrants are immediately exercisable upon grant. The aggregate intrinsic value of options exercised in 201 6 and 201 5 was (AUD 1,731 ) and (AUD 592 ) , respectively. Additional information related to options and warrants outstanding at June 30, 201 6 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 3.8 cents 229,582,240 0.75 0.038 3.3 cents 87,033,246 1.83 0.033 3.9 cents 4,000,000 1.42 0.039 320,615,486 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Jun. 30, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 11. RELATED PARTY TRANSACTIONS There were no related party transactions during the years ended June 30, 201 6 and 201 5. |
Commitments
Commitments | 12 Months Ended |
Jun. 30, 2016 | |
Commitments [Abstract] | |
Commitments | 12. COMMITMENTS Contractual Obligations Total 2017 2018 2019 2020 2021 Thereafter Asset retirement obligations (1) $ 3,750,245 $ 300,000 $ - $ - $ - $ - $ 3,450,245 Leases (2) 484,246 68,253 96,199 100,152 103,616 107,079 8,947 Credit Facility (3) 30,500,000 11,500,000 19,000,000 - - - - Promissory Note (4) 4,400,000 4,400,000 - - - - - Total 39,134,491 16,268,253 19,096,199 100,152 103,616 107,079 3,459,192 (1) Asset retirement obligations represent the estimated fair value at June 30, 201 6 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors. (2) (3) Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Excludes variable rate debt interest payments related to the Company’s credit facility. The interest rate is LIBOR plus 3.75% or approximately 6 . 3 % at June 30, 201 6 . (4) Includes fixed interest costs payable at the promissory notes maturity date on April 1, 2017. The interest rate is 10% per annum. Leases –The Company has entered into lease agreements for office space in Denver, Colorado and Perth, Western Australia. As of June 30, 201 6 , future minimum lease payments under operating leases that have initial or remaining non–cancelable terms in excess of one year are $ 68,253 in 201 7 , $ 96,199 in 201 8 , $100,152 in 2019, $103,616 in 2020, $107,079 in 2021 and $ 8,947 thereafter. Net rent expense incurred for office space was $ 157,094 and $ 139,599 in 201 6 and 201 5 , respe c tively . |
Contingencies
Contingencies | 12 Months Ended |
Jun. 30, 2016 | |
Contingencies [Abstract] | |
Contingencies | 13. CONTINGENCIES There are no unrecorded contingent assets or liabilities in place for the Company at June 30, 2016 (2015: Nil) . 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. During the year ended June 30, 2016 the Company recognized a gain in other income of $0.8 million with respect to a settlement from litigation with Haliburton Company. Haliburton paid the Company $0.7 million and forgave revenue owing of $0.1 million. A contingent receivable was not recognized prior to the settlement as the amount of the settlement was not reasonably estimable. Liquidity Following the sustained decline in oil prices, the Company became out of compliance with its loan to value ratio with Mutual of Omaha Bank. The Company is required to pay down $11.5 million of the proceeds from the pending sale of North Stockyard to Mutual of Omaha Bank. The Company is also required to raise $5 million in equity prior to September 30, 2016. The Company raised $1.4 million in equity in April 2016 and we have been granted an extension in this deadline to November 15, 2016 . It is expected that Mutual of Omaha will also apply the remaining proceeds from the North Stockyard sale to this equity raise, however that is not certain. The Company intends to meet its obligation to raise equity by September 30, 2016 and has not asked for a waiver from this requirement. Following the pay down of the facility from the proceeds from the pending North Stockyard sale, the Company intends to enter into negotiations with Mutual of Omaha Bank to renegotiate the term and conditions of its credit facility, including the current maturity date and covenants. While the new borrowing based is currently being determined by Mutual of Omaha Bank, based on the Company’s proved reserves the Company expects the borrowing base will be in excess of the current drawdown creating additional liquidity in the facility. Should the Company not be able to renegotiate the credit facility to its satisfaction the Company may need to consider further asset sales or capital raises to provide the Company with ongoing liquidity to repay its long and short term debts as and when they fall due. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Jun. 30, 2016 | |
Subsequent Events [Abstract] | |
Subsequent Events | 14. SUBSEQUENT EVENTS There have been no material subsequent events through the date of filing. |
Quarterly Financial Data
Quarterly Financial Data | 12 Months Ended |
Jun. 30, 2016 | |
Quarterly Financial Data [Abstract] | |
Quarterly Financial Data | 15. QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited financial data for each quarter for the years ended June 30, 201 6 and 201 5 (except per share data): Three Months Ended June 30, 2016 March 31, 2016 Dec 31, 2015 Sep 30, 2015 Year ended June 30, 2015: Revenues $ 8,576,792 $ 3,041,563 $ 5,009,633 $ 4,049,615 (Loss)/income from operations 2,822,938 (1,944,025) (2,538,571) (10,974,251) Tax (expense)/benefit - - - - Net (loss)/income 2,822,938 (1,944,025) (2,538,571) (10,974,251) Basic (loss)/earnings per common share – cents per share 0.16 (0.07) (0.09) (0.43) Diluted (loss)/earnings per common share – cents per share 0.16 (0.07) (0.09) (0.43) Three Months Ended June 30, 2015 March 31, 2015 Dec 31, 2014 Sep 30, 2014 Year ended June 30, 2015: Revenues $ 4,475,079 $ 3,041,563 $ 5,009,633 $ 4,049,615 Loss from operations (21,159,764) (1,944,025) (2,538,571) (10,974,251) Tax (expense)/benefit (3,021) - - - Net (loss)/income (21,162,785) (1,944,025) (2,538,571) (10,974,251) Basic loss per common share – cents per share (0.70) (0.07) (0.09) (0.43) Diluted loss per common share – cents per share (0.70) (0.07) (0.09) (0.43) |
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, 2016 | |
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 | 16. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES, INCLUSIVE OF DISCONTINUED OPERATIONS (UNAUDITED) Oil and Gas Reserves The information set forth below regarding the Company’s oil and gas reserves, for the year ended June 30, 201 6 was prepared by Netherland, Sewell, & Associates Inc and the reserves for the years ended June 30 , 201 5 were prepared by Ryder Scott Company L.P., both independent reserve engineering firm s . The CEO reviews all reserve reports. All reserves are located within the continental United States. 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, 2016 2015 Work in progress - - Development 31,332,473 18,339,362 Exploration costs - 1,449,750 Undeveloped capitalized acreage 178,254 23,130 Total costs incurred $ 31,510,727 $ 19,812,242 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, 2016 Year ended June 30, 2015 Oil Gas Total Oil Gas Total Mbbls MMcf MBOE Mbbls MMcf MBOE Beginning of year 1,285 1,183 1,483 1,478 1,763 1,773 Revisions of previous quantity estimates 2,597 2,662 3,041 (376) (547) (467) Extensions and discoveries - - - 414 193 446 Sale of reserves in place - - - - - - Acquisitions 6,340 5,317 7,226 - - - Production (240) (569) (335) (231) (226) (269) End of year 9,982 8,593 11,415 1,285 1,183 1,483 Proved developed producing reserves 3,724 3,092 4,240 1,285 1,183 1,483 Proved developed non producing 970 1,800 1,270 - - - Proved undeveloped reserves 5,288 3,701 5,905 - - - Total proved reserves 9,982 8,593 11,415 1,285 1,183 1,483 During the year ended June 30, 2016 the acquisition of reserves relates to our Foreman Butte acquisition. The revisions to previous quantity estimates relates to workovers performed on wells associated with the Foreman Butte acquisition. During the year ended June 30, 2015 the increase in extensions and discoveries relates to the drilling of our wells which were not previously PUD locations. 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. 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, 201 6 and 20 15 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, 201 6 and 20 15 were $ 0.37 and $4.30 per Mcf, respectively. The 12 month historical average of the first of the month prices used for oil for June 30, 201 6 and 201 5 were $ 37.12 and $ 59.64 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. During the year ended June 30, 2015 we converted two PUD locations to PDP locations. We also drilled and completed eight other wells that were not recorded as PUD’s at June 30, 2014. At June 30, 2015 we have no PUD locations in our reserve value. Samson has not disclosed the impact of taxes in the future cash flows for the years ended June 30, 2015 and 2016 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, 2016 2015 2014 2013 2012 Future cash inflows $ 373,740 $ 72,900 $ 148,975 $ 133,589 $ 71,655 Future production costs (184,691) (22,403) (43,009) (44,672) (29,321) Future development costs (50,752) (38) (12,461) (29,012) (10,198) Future income taxes - - (21,819) (12,050) (5,524) Future net cashflows 138,297 50,459 71,686 47,855 26,612 10 % discount (71,550) (16,206) (29,093) (26,012) (13,274) Standardized measure of discounted future net cash flows relating to proved reserves $ 66,747 $ 34,253 $ 42,593 $ 21,843 $ 13,338 The principal sources of changes in the standardized measure of discounted future net cash flows during the periods ended June 30, 2016 and June 30, 201 5 are as follows (in US$’000’s): Fiscal Year Ended June 30 2016 2015 Beginning of year $ 34,253 $ 42,593 Sales of oil and gas produced during the period, net of production costs (3,575) (7,178) Net changes in prices and production costs (15,705) (22,610) Previously estimated development costs incurred during the period - 1,898 Changes in estimates of future development costs (14,545) - Extensions and discoveries - 11,266 Revisions of previous quantity estimates and other 18,074 (6,197) Sale of reserves in place - - Purchase of reserves in place 41,564 - Change in future income taxes - 11,809 Accretion of discount 3,452 5,440 Other 3,229 (2,768) Balance at end of year $ 66,747 $ 34,253 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. For the year ended June 30, 2015 the impact of changes in estimates of future development costs have been included in revisions of previous quantity estimates as they relate to the loss of PUD’s in the current pricing environment. |
Summary Of Significant Accoun23
Summary Of Significant Accounting Policies (Policy) | 12 Months Ended | |
Jun. 30, 2016 | 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, Montana and Wyoming. 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. All 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, 201 6 or 201 5 . | |
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 2016 2015 Oil and natural gas sales $ 1,717,110 $ 3,224,595 Cost recovery from drilling partners 275,018 275,148 Other 4,287 145,480 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015 $ 1,996,415 $ 3,645,223 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. The cost recovery from drilling partners relates to the partners share of drilling costs associated with the current drilling program in our North Stockyard infill project and Hawk Springs project. | |
Accruals | Accruals. The components of accrued liabilities for the years ended June 30, 201 6 and 201 5 are as follows: 2016 2015 Bonus accrual - - Other accruals 629,975 1,999,344 Deposit received for asset sale 1,000,000 0 $ 1,629,975 $ 1,999,344 Other accruals includes an estimate of the costs expected to be incurred with respect to the asset retirement obligation in the next twelve months. The deposit received from the asset sale is non-refundable (subject to the identification of certain title or environmental defects for the deadline for providing notification to the Company has passed) deposit received from the purchaser of our North Stockyard assets. The majority of other accruals in the prior year relate to expenses incurred in relation to our exploratory well, Bluff, in our Hawk Springs project and other general accruals. | |
Oil And Natural Gas Properties | Oil and Gas Properties. Oil and gas properties and equipment consist of the following at June 30: 2016 2015 Proved properties $ 45,177,047 $ 61,724,561 Lease and well equipment 1,394,291 12,264,955 Less accumulated depreciation, depletion and impairment (15,049,015) (44,273,976) $ 31,522,323 $ 29,715,540 Assets held for sale 13,768,865 - Unproved acreage $ 220,703 $ 2,491,422 Capitalized exploration expense $ - $ 1,388,798 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 consider s numerous factors including, but not limited to, current development and exploration drilling plans, favorable or unfavorable exploration activity on adjacent leaseholds, in-house geologists' evaluation of the lease, future reserve cash flows and the remaining lease term . Assets held for sale On June 30, 2016, the Company signed a Purchase and Sale Agreement for the sale of its interests in the North Stockyard field. The purchase price of the acquisition is $15 million and the acquisition is expected to settle on October 20, 2016. The effective date of the acquisition is the day after the closing date. The Company received a $1 million deposit from the purchaser on the date of signing, recorded in current liabilities. This deposit is only refundable if certain title or environmental defects are identified during the purchasers due diligence. The date by which the purchaser was required to notify the Company of any title or environmental defects has passed and the Company was not advised of any environmental or title defects. | |
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 conclude s that it is unlikely to recover the expenditure by future exploitation or sale, then the relevant capitalized amount will be written off to the income statement. During the fiscal year ended June 30, 2016, we expensed $4.2 million in deferred exploration expense in relation to our Hawk Springs project area. During the fiscal year ended June 30, 2015 the Company expensed $8.1 million in relation to our Roosevelt project in Montana. During the year ended June 30, 2014 the Company entered into a farm out arrangement with respect to this property however due to the falling oil prices, the farm out partner failed to meet it’s obligations under the agreement. The Company do es not plan to spend any additional capital in this project area and therefore we have written off the previously capitalized exploration expenditure. The Company also wrote off $2.5 million with respect to its South Prairie project in North Dakota. A second dry hole was drilled in the area during the year ended June 30, 2015 and the decision was made to write off the costs capitalized with respect to this project. The Company also expensed $ 1.6 million with respect to its Hawk Springs project in Wyoming. These costs were associated with leases expiring during the year. The Company also expensed $0.4 million of general exploration expenditure, which was never capitalized to the Balance Sheet. | |
Impairment | Impairment The Company recorded impairment charges of $ 11.0 million and $ 21.5 million for the years ended June 30, 201 6 and 201 5 respectively. The charges in the fiscal year ended June 30, 2016 related to the impact of the drop in the oil price on our North Stockyard, Rainbow and State GC project areas. The charges in the fiscal year ended June 30, 2015 related to the impact of the drop in the oil price on our Rainbow and North Stockyard projects in North Dakota. | |
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, 201 6 a nd 201 5 was $0.1 million and $ 0.1 million, respectively. Other property and equipment consists of the following at June 30: 2016 2015 Furniture, fittings and equipment $ 882,469 $ 801,949 Less accumulated depreciation (573,995) (553,428) $ 308,474 $ 248,521 | |
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, 2016 2015 Dilutive - - Anti–dilutive 321,955,194 357,099,676 | |
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 Australia n dollars. The functional and presentation currency of Samson Oil & Gas USA, Inc. (subsidiary) is U.S dollars. The pres entation 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 |
Summary Of Significant Accoun24
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Summary Of Significant Accounting Policies [Abstract] | |
Schedule Of Components Of Accounts Receivable | June 30 2016 2015 Oil and natural gas sales $ 1,717,110 $ 3,224,595 Cost recovery from drilling partners 275,018 275,148 Other 4,287 145,480 Total accounts receivable, net of nil allowance for doubtful accounts for June 30, 2016 and 2015 $ 1,996,415 $ 3,645,223 |
Schedule Of Components Of Accrued Liabilities | 2016 2015 Bonus accrual - - Other accruals 629,975 1,999,344 Deposit received for asset sale 1,000,000 0 $ 1,629,975 $ 1,999,344 |
Schedule Of Other Property And Equipment | 2016 2015 Furniture, fittings and equipment $ 882,469 $ 801,949 Less accumulated depreciation (573,995) (553,428) $ 308,474 $ 248,521 |
Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities | Year ended June 30, 2016 2015 Dilutive - - Anti–dilutive 321,955,194 357,099,676 |
Business Combination (Tables)
Business Combination (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Business Combination [Abstract] | |
Schedule Of Business Acquisition | USD Amount Settled in Cash $ 1,391,874 Extension of credit facility 11,500,000 Fair value of promissory note provided 3,928,571 Fair value of consideration transferred 16,820,445 - Recognised amounts of identifiable assets and liabilities: Oil and gas properties 29,350,256 Oil inventory acquired 463,768 Trade receivables 53,540 Revenue in suspense assumed (403,612) Asset retirement obligation assumed (1,868,276) Net identifiable assets and liabilities 27,595,676 Gain on bargain purchase 10,775,231 |
Schedule Of Pro Forma Information | Contribution of Business Combination to Company Results The following represents the amount of the Company's revenue and losses for the years ended June 30, 2016 and June 30, 2015, assuming the business combination occurred on July 1, 2014. 2016 2015 Revenues $ 25,579,347 $ 19,849,812 Losses (15,762,744) (35,982,244) |
Hedging And Derivative Financ26
Hedging And Derivative Financial Instruments (Tables) | 12 Months Ended |
Jun. 30, 2015 | |
Hedging And Derivative Financial Instruments [Abstract] | |
Schedule Of Open Derivative Contracts | At June 30, 2015 the Company’s open derivative contracts consisted of the following: Oil Price Collars – WTI Volumes (bbls) Floor US$ Ceiling US$ January 2016 - February 2016 2,788 85.00 89.85 Oil Price Swaps – WTI Volumes (bbls) Price US$ July 2015 - December 2015 8,765 105.00 January 2016 - February 2016 2,788 105.00 Oil Price Three Way Swaps - WTI Volumes (bbls) Ceiling US$ Sub Floor US$ Floor US$ July 2015 - December 201 5 55,200 70.25 32.50 45.00 January 2016 - December 2016 27,450 80.00 40.00 55.00 January 2016 – December 2016 36,600 - 67.50 82.50 During the year ended June 30, 2016, the Company recognized $2.7 million in the Statement of Operations in loss in derivative instruments. As of June 30, 2016, the derivative instruments were valued at a unrealized loss of $2.8 million of which, $1.6 million is recorded as a current liability and $1.2 million is recorded as a non-current liability. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Fair Value Measurements [Abstract] | |
Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis | Fair Value at June 30, 2016 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 2,654,812 $ - $ - $ - $ 2,654,812 Derivative Instruments - 136,727 - (136,727) - Non Current Assets: Derivative Instruments - 220,317 - (220,317) - Current Liabilities Derivative Instruments - 1,808,380 - (136,727) 1,671,653 Non Current Liabilities: Derivative Instruments 1,453,393 (220,317) 1,233,076 Fair Value at June 30, 2015 Level 1 Level 2 Level 3 Netting (1) Total Current Assets: Cash and cash equivalents $ 2,062,720 $ - $ - $ - $ 2,062,720 Derivative Instruments - 379,540 - (220,324) 159,216 Non Current Assets: Derivative Instruments - 298,703 - (197,434) 101,269 Current Liabilities Derivative Instruments - 220,324 - (220,324) - Non Current Liabilities: Derivative Instruments 197,434 (197,434) - |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Asset Retirement Obligations [Abstract] | |
Summary Of Activities Of Asset Retirement Obligations | 2016 2015 Asset retirement obligations at beginning of period $ 1,810,674 $ 1,775,792 Liabilities incurred or acquired 1,868,276 672,339 Liabilities settled (53,783) (677,616) Disposition of properties - - Accretion expense 125,078 40,159 Asset retirement obligations at end of period 3,750,245 1,810,674 Less: current asset retirement obligations (classified with accounts payable and accrued liabilities) (300,000) (547,000) Long-term asset retirement obligations $ 3,450,245 $ 1,263,674 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Income Taxes [Abstract] | |
Schedule Of Components Of Income Tax Provision (Benefit) | June 30 2016 2015 Current: Federal $ - $ 2,821 State - 200 - 3,021 Deferred: Federal - - State - - Total income tax provision (benefit) $ - $ 3,021 |
Schedule Of Effective Income tax Rate Reconciliation | June 30 2016 2015 Income tax expense (benefit) at federal statutory rate $ (3,790,398) $ (10,984,983) State income taxes (228,568) (472,583) Alternative minimum tax - 2,821 Other adjustments - true up of deferred balances (498,257) (1,101,884) Other - change in deferred tax rate (188,080) 60,666 Other (550,957) (1,562,773) Valuation allowance 5,256,260 14,061,757 $ - $ 3,021 |
Schedule Of Components Of Deferred Tax Assets and (Liabilities) | June 30 201 6 201 5 Deferred income tax assets: Net operating losses $ 33,548,583 $ 25,995,717 Asset retirement obligation 1,395,262 458,869 Annual leave 60,826 71,309 Abandonment limitation 446,543 145,000 Accrued bonus - 64,789 Charitable contributions 876 862 AMT credit 780,443 780,443 Share based compensation 500,844 500,844 Oil and Gas Property - 157,481 Derivative liability 1,071,109 - Valuation allowance (33,337,136) (28,080,876) Deferred income tax liabilities: Commodity liability - (94,588) Amortization - loan costs - - Oil and gas property (4,467,350) - Net deferred income tax assets (liabilities) - - Net current deferred tax asset - - Noncurrent deferred tax liability $ - $ - |
Summary Of Valuation Allowance | June 30 2016 2015 Deferred Income Tax Valuation Allowance Balance at July 1 28,080,876 14,019,119 Additions (reductions) to deferred income tax expense 5,256,260 14,061,757 Balance at June 30 33,337,136 28,080,876 |
Reconciliation Of Gross Uncertain Tax Positions | 201 6 201 5 Total gross uncertain tax positions at beginning of year $ - $ 107,524 Additions / Reductions for tax positions of prior years - - Additions / Reductions for tax positions of current year - - Reductions due to settlements with taxing authorities - (107,524) Reductions due to lapse of statute of limitations - - Total amount of gross uncertain tax positions at end of year $ - $ - |
Capital Stock Contributed Equ30
Capital Stock Contributed Equity (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Capital Stock Contributed Equity [Abstract] | |
Contributed Equity | Consolidated Entity 2016 2015 3,215,854,701 ordinary fully paid shares including shares to be issued $ 105,719,184 $ 104,491,774 (2015 – 2,837,782,022 ordinary fully paid shares including shares to be issued) |
Movements In Contributed Equity For The Year | Movements in contributed equity for the year 2016 2015 No. of shares $ No. of shares $ Opening balance 2,837,782,022 104,491,774 2,837,756,933 104,535,894 Capital raising (i) 378,020,400 1,398,675 - - Shares issued upon exercise of options (ii) 52,279 1,475 25,089 880 Stock based compensation (options issued) - - - - Transaction costs incurred - (172,740) - (45,000) Shares on issue at balance date 3,215,854,701 105,719,184 2,837,782,022 104,491,774 318,452,166 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) Equity raised during the fiscal year ended June 30, 2016 In April 2016, we issued 378,020,400 ordinary shares at a purchase price of $0.0036 per share to raise $1.4 million in a private placement to certain institutional investors. (ii) During the course of the year the Company issue d 5 2,279 (201 5 : 2 5,089 ) ordinary shares upon the exercise of 5 2 , 279 (201 5 : 2 5,089 ) options. |
Cash Flow Statement (Tables)
Cash Flow Statement (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Cash Flow Statement [Abstract] | |
Schedule Of Cash Flow Statement | Year ended June 30 2016 2015 A reconciliation of the net loss to the net cash provided by operations is as follows: Net loss after tax $ (12,633,909) $ (36,619,632) Depreciation 4,766,949 6,920,945 Accretion of asset retirement obligations 125,078 40,159 Exploration and evaluation expenditures 4,216,077 12,686,943 Impairment losses of oil and gas properties 11,029,442 21,475,450 Borrowing costs 185,138 135,694 Change in fair value of derivative instruments 2,644,244 (673,859) Bargain purchase on acquistion (10,775,231) - Abandonment costs - 404,485 Changes in assets and liabilities: Decrease in receivables 1,648,678 667,223 Decrease in employee benefits (24,917) (10,897) Increase/(decrease) in payables 750,428 (1,982,072) NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES $ 1,931,977 $ 3,044,439 |
Credit Facility (Tables)
Credit Facility (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Credit Facility [Abstract] | |
Schedule of Credit Facilities | June 30, 2016 2015 Credit facility at beginning of period $ 18,699,000 $ 6,000,000 Cash advanced under facility 11,801,000 13,000,000 Repayments - (301,000) Credit facility at end of period $ 30,500,000 $ 18,699,000 Less fund due for repayment in the next 12 months (11,500,000) - Total amount outstanding in long term credit facility $ 19,000,000 $ 18,699,000 Funds available for drawdown under the facility - - |
Share-Based Payments (Tables)
Share-Based Payments (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
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 3.8 cents 229,582,240 0.75 0.038 3.3 cents 87,033,246 1.83 0.033 3.9 cents 4,000,000 1.42 0.039 320,615,486 |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Jun. 30, 2015 | |
Commitments [Abstract] | |
Contractual Obligations | Contractual Obligations Total 2017 2018 2019 2020 2021 Thereafter Asset retirement obligations (1) $ 3,750,245 $ 300,000 $ - $ - $ - $ - $ 3,450,245 Leases (2) 484,246 68,253 96,199 100,152 103,616 107,079 8,947 Credit Facility (3) 30,500,000 11,500,000 19,000,000 - - - - Promissory Note (4) 4,400,000 4,400,000 - - - - - Total 39,134,491 16,268,253 19,096,199 100,152 103,616 107,079 3,459,192 |
Quarterly Financial Data (Table
Quarterly Financial Data (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Quarterly Financial Data [Abstract] | |
Schedule Of Quarterly Financial Data | Three Months Ended June 30, 2016 March 31, 2016 Dec 31, 2015 Sep 30, 2015 Year ended June 30, 2015: Revenues $ 8,576,792 $ 3,041,563 $ 5,009,633 $ 4,049,615 (Loss)/income from operations 2,822,938 (1,944,025) (2,538,571) (10,974,251) Tax (expense)/benefit - - - - Net (loss)/income 2,822,938 (1,944,025) (2,538,571) (10,974,251) Basic (loss)/earnings per common share – cents per share 0.16 (0.07) (0.09) (0.43) Diluted (loss)/earnings per common share – cents per share 0.16 (0.07) (0.09) (0.43) Three Months Ended June 30, 2015 March 31, 2015 Dec 31, 2014 Sep 30, 2014 Year ended June 30, 2015: Revenues $ 4,475,079 $ 3,041,563 $ 5,009,633 $ 4,049,615 Loss from operations (21,159,764) (1,944,025) (2,538,571) (10,974,251) Tax (expense)/benefit (3,021) - - - Net (loss)/income (21,162,785) (1,944,025) (2,538,571) (10,974,251) Basic loss per common share – cents per share (0.70) (0.07) (0.09) (0.43) Diluted loss per common share – cents per share (0.70) (0.07) (0.09) (0.43) |
Supplemental Information On O36
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
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, 2016 2015 Work in progress - - Development 31,332,473 18,339,362 Exploration costs - 1,449,750 Undeveloped capitalized acreage 178,254 23,130 Total costs incurred $ 31,510,727 $ 19,812,242 |
Schedule Of Proved Developed And Undeveloped Oil And Gas Reserve Quantities | Year ended June 30, 2016 Year ended June 30, 2015 Oil Gas Total Oil Gas Total Mbbls MMcf MBOE Mbbls MMcf MBOE Beginning of year 1,285 1,183 1,483 1,478 1,763 1,773 Revisions of previous quantity estimates 2,597 2,662 3,041 (376) (547) (467) Extensions and discoveries - - - 414 193 446 Sale of reserves in place - - - - - - Acquisitions 6,340 5,317 7,226 - - - Production (240) (569) (335) (231) (226) (269) End of year 9,982 8,593 11,415 1,285 1,183 1,483 Proved developed producing reserves 3,724 3,092 4,240 1,285 1,183 1,483 Proved developed non producing 970 1,800 1,270 - - - Proved undeveloped reserves 5,288 3,701 5,905 - - - Total proved reserves 9,982 8,593 11,415 1,285 1,183 1,483 |
Schedule Of Estimated Standardized Measure Of Discounted Future Net Cash Flows Relating To Proved Reserves | As at June 30, 2016 2015 2014 2013 2012 Future cash inflows $ 373,740 $ 72,900 $ 148,975 $ 133,589 $ 71,655 Future production costs (184,691) (22,403) (43,009) (44,672) (29,321) Future development costs (50,752) (38) (12,461) (29,012) (10,198) Future income taxes - - (21,819) (12,050) (5,524) Future net cashflows 138,297 50,459 71,686 47,855 26,612 10 % discount (71,550) (16,206) (29,093) (26,012) (13,274) Standardized measure of discounted future net cash flows relating to proved reserves $ 66,747 $ 34,253 $ 42,593 $ 21,843 $ 13,338 |
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows | Fiscal Year Ended June 30 2016 2015 Beginning of year $ 34,253 $ 42,593 Sales of oil and gas produced during the period, net of production costs (3,575) (7,178) Net changes in prices and production costs (15,705) (22,610) Previously estimated development costs incurred during the period - 1,898 Changes in estimates of future development costs (14,545) - Extensions and discoveries - 11,266 Revisions of previous quantity estimates and other 18,074 (6,197) Sale of reserves in place - - Purchase of reserves in place 41,564 - Change in future income taxes - 11,809 Accretion of discount 3,452 5,440 Other 3,229 (2,768) Balance at end of year $ 66,747 $ 34,253 |
Summary Of Significant Accoun37
Summary Of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | ||
Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($)segment | Jun. 30, 2014USD ($) | |
Significant Accounting Policies [Line Items] | |||
Number of operating segments | segment | 1 | ||
Impairment of oil and natural gas properties | $ 11,029,442 | $ 21,475,450 | |
Depreciation and amortization | 4,766,949 | 6,920,945 | |
Minimum percentage of likelihood tax benefits recognized from uncertain tax position, reasonably possible upon settlement | 50.00% | ||
Proved properties | 45,177,047 | 61,724,561 | |
Roosevelt project [Member] | |||
Significant Accounting Policies [Line Items] | |||
Capiltalized exploration expense written off | 8,100,000 | ||
South Prairie Project [Member] | |||
Significant Accounting Policies [Line Items] | |||
Capiltalized exploration expense written off | 2,500,000 | ||
Hawk Springs Project [Member] | |||
Significant Accounting Policies [Line Items] | |||
Capiltalized exploration expense written off | $ 1,600,000 | ||
Other Property And Equipment [Member] | |||
Significant Accounting Policies [Line Items] | |||
Depreciation and amortization | $ 100,000 | $ 100,000 | |
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 Accoun38
Summary Of Significant Accounting Policies (Schedule Of Components Of Accounts Receivable) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2013 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | $ 1,996,415 | $ 3,645,223 | ||
Accounts receivable, allowance for doubtful accounts | ||||
Oil And Natural Gas Sales Related Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | 1,717,110 | 3,224,595 | ||
Cost Recovery From JV Partner Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | 275,018 | 275,148 | ||
Other Receivable [Member] | ||||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||||
Accounts receivable | $ 4,287 | $ 145,480 |
Summary Of Significant Accoun39
Summary Of Significant Accounting Policies (Schedule Of Components Of Accrued Liabilities) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Summary Of Significant Accounting Policies [Abstract] | ||
Other accruals | $ 629,975 | $ 1,999,344 |
Deposit Received for asset sale | 1,000,000 | |
Total accrued liabilities | $ 1,629,975 | $ 1,999,344 |
Summary Of Significant Accoun40
Summary Of Significant Accounting Policies (Schedule Of Oil And Gas Properties And Equipment) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Summary Of Significant Accounting Policies [Abstract] | ||
Proved properties | $ 45,177,047 | $ 61,724,561 |
Lease and well equipment | 1,394,291 | 12,264,955 |
Less accumulated depreciation, depletion and impairment | (15,049,015) | (44,273,976) |
Total oil and gas properties and equipment | 31,522,323 | 29,715,540 |
Undeveloped capitalized acreage | $ 220,703 | 2,491,422 |
Capitalized exploration expense | $ 1,388,798 |
Summary Of Significant Accoun41
Summary Of Significant Accounting Policies (Schedule Of Other Property And Equipment) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Summary Of Significant Accounting Policies [Abstract] | ||
Furniture, fittings and equipment | $ 882,469 | $ 801,949 |
Less accumulated depreciation | (573,995) | (553,428) |
Total other property and equipment | $ 308,474 | $ 248,521 |
Summary Of Significant Accoun42
Summary Of Significant Accounting Policies (Schedule Of Weighted Average Dilutive And Anti-Dilutive Securities) (Details) - shares | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Diluted weighted average common shares outstanding | 2,919,426,154 | 2,837,777,322 |
Options And Warrants [Member] | ||
Anit-dilutive weighted average common shares outstanding | 321,955,194 | 357,099,676 |
Summary Of Significant Accoun43
Summary Of Significant Accounting Policies (Schedule Of Earnings Per Share, Basic And Diluted) (Details) - $ / shares | 3 Months Ended | 12 Months Ended | ||||||||
Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2016 | Jun. 30, 2015 | |
Summary Of Significant Accounting Policies [Abstract] | ||||||||||
Basic weighted average common shares outstanding | 2,919,426,154 | 2,837,777,322 | ||||||||
Diluted weighted average common shares outstanding | 2,919,426,154 | 2,837,777,322 | ||||||||
Continuing operations, basic earnings per common share - cents per share | $ 0.16 | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.70) | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.43) | $ (1.29) |
Diluted earnings per common share - cents per share | $ 0.16 | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.70) | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.43) | $ (1.29) |
Business Combination (Narrative
Business Combination (Narrative) (Details) | 12 Months Ended |
Jun. 30, 2016USD ($) | |
Business Acquisition [Line Items] | |
Acquisition cost settled in cash and promissory note | $ 16,600,000 |
Extension of credit facility | 11,500,000 |
Fair value of promissory note provided | $ 3,928,571 |
Effective interest rate | 6.30% |
Acquisition costs | $ 200,000 |
Promissory Note [Member] | |
Business Acquisition [Line Items] | |
Effective interest rate | 12.00% |
Face amount | $ 4,000,000 |
Interest rate | 10.00% |
Business Combination (Schedule
Business Combination (Schedule Of Business Acquisition) (Details) | 12 Months Ended |
Jun. 30, 2016USD ($) | |
Business Combination [Abstract] | |
Amount Settled in Cash | $ 1,391,874 |
Extension of credit facility | 11,500,000 |
Fair value of promissory note provided | 3,928,571 |
Fair value of consideration transferred | 16,820,445 |
Oil and gas properties | 29,350,256 |
Oil inventory acquired | 463,768 |
Trade receivables | 53,540 |
Revenue in suspense assumed | (403,612) |
Asset retirement obligation assumed | (1,868,276) |
Net identifiable assets and liabilities | 27,595,676 |
Gain on bargain purchase | $ 10,775,231 |
Business Combination (Schedul46
Business Combination (Schedule Of Pro Forma Information) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Business Combination [Abstract] | ||
Revenues | $ 25,579,347 | $ 19,849,812 |
Losses | $ (15,762,744) | $ (35,982,244) |
Hedging And Derivative Financ47
Hedging And Derivative Financial Instruments (Narrative) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Hedging And Derivative Financial Instruments [Abstract] | ||
Fair value of derivative instruments | $ 101,269 | |
Fair value of derivative instruments | 159,216 | |
Derivative Instruments Not Designated as Hedging Instruments, Liability, at Fair Value | $ 1,233,076 | |
Derivative Liability, Current | 1,671,653 | |
Derivative Liability, Noncurrent | 1,233,076 | |
Loss on Derivative Instruments, Pretax | $ 2,657,963 | |
Gain on derivative instruments | $ 3,112,268 |
Hedging And Derivative Financ48
Hedging And Derivative Financial Instruments (Schedule Of Open Derivative Contracts) (Details) | 3 Months Ended | 12 Months Ended |
Sep. 30, 2016bbl / MMBTU$ / bblbbl | Jun. 30, 2015USD ($)$ / bblbbl | |
Derivative Contract One [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jan. 1, 2016 | |
Derivative maturity | Feb. 1, 2016 | |
Volumes | bbl | 2,788 | |
Floor price | 85 | |
Ceiling price | 89.85 | |
Derivative Contract Two [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jul. 1, 2015 | |
Derivative maturity | Dec. 1, 2015 | |
Volumes | bbl | 8,765 | |
Price | 105 | |
Derivative Contract Three [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jan. 1, 2016 | |
Derivative maturity | Feb. 1, 2016 | |
Volumes | bbl | 2,788 | |
Price | 105 | |
Derivative Contract Four [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jul. 1, 2015 | |
Derivative maturity | Dec. 1, 2015 | |
Volumes | bbl | 55,200 | |
Sub floor | $ | $ 32.50 | |
Floor price | 45 | |
Ceiling price | 70.25 | |
Derivative Contract Five [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jan. 1, 2016 | |
Derivative maturity | Dec. 1, 2016 | |
Volumes | bbl | 27,450 | |
Sub floor | $ | $ 40 | |
Floor price | 55 | |
Ceiling price | 80 | |
Derivative Contract Six [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jan. 1, 2016 | |
Derivative maturity | Dec. 1, 2016 | |
Volumes | bbl | 36,600 | |
Sub floor | $ | $ 67.50 | |
Floor price | 82.50 | |
Derivative Contract Seven [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jul. 1, 2016 | |
Derivative maturity | Apr. 30, 2018 | |
Volume (BO/Mmbtu) | bbl / MMBTU | 133,032 | |
Floor price | 41.50 | |
Ceiling price | 63 | |
Derivative Contract Eight [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jul. 1, 2016 | |
Derivative maturity | Oct. 31, 2016 | |
Volume (BO/Mmbtu) | bbl / MMBTU | 127,229 | |
Floor price | 1.90 | |
Ceiling price | 2.40 | |
Derivative Contract Nine [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Nov. 1, 2016 | |
Derivative maturity | Mar. 31, 2017 | |
Volume (BO/Mmbtu) | bbl / MMBTU | 134,088 | |
Floor price | 2.60 | |
Ceiling price | 3.35 | |
Derivative Contract Ten [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Apr. 1, 2017 | |
Derivative maturity | Oct. 31, 2017 | |
Volume (BO/Mmbtu) | bbl / MMBTU | 167,682 | |
Floor price | 2.40 | |
Ceiling price | 2.91 | |
Derivative Contract Eleven [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Nov. 1, 2017 | |
Derivative maturity | Apr. 30, 2018 | |
Volume (BO/Mmbtu) | bbl / MMBTU | 127,030 | |
Floor price | 2.80 | |
Ceiling price | 3.60 | |
Derivative Contract Twelve [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jul. 1, 2016 | |
Derivative maturity | Dec. 31, 2016 | |
Volumes | bbl | 83,730 | |
Floor price | 41.20 | |
Derivative Contract Thirteen [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jan. 1, 2017 | |
Derivative maturity | Dec. 31, 2017 | |
Volumes | bbl | 141,255 | |
Floor price | 44.09 | |
Derivative Contract Fourteen [Member] | ||
Derivative [Line Items] | ||
Derivative inception | Jan. 1, 2018 | |
Derivative maturity | Apr. 30, 2018 | |
Volumes | bbl | 39,720 | |
Floor price | 45.55 |
Fair Value Measurements (Schedu
Fair Value Measurements (Schedule Of Fair Value, Assets And Liabilities Measured On Recurring And Nonrecurring Basis) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | |
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | $ 2,654,812 | $ 2,062,720 | |
Current Assets, Derivative Instruments | 159,216 | ||
Non Current Assets, Derivative Instruments | 101,269 | ||
Current Liabilities, Derivative Instruments | 1,671,653 | ||
Non Current Liabilities, Derivative Instruments | 1,233,076 | ||
Level 1 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | 2,654,812 | 2,062,720 | |
Level 2 [Member] | |||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | |||
Cash and cash equivalents | |||
Current Assets, Derivative Instruments | 136,727 | 379,540 | |
Non Current Assets, Derivative Instruments | 220,317 | 298,703 | |
Current Liabilities, Derivative Instruments | 1,808,380 | 220,324 | |
Non Current Liabilities, Derivative Instruments | 1,453,393 | 197,434 | |
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] | (136,727) | (220,324) |
Non Current Assets, Derivative Instruments | [1] | (220,317) | (197,434) |
Current Liabilities, Derivative Instruments | [1] | (136,727) | (220,324) |
Non Current Liabilities, Derivative Instruments | [1] | $ (220,317) | $ (197,434) |
[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 | 24 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2016 | |||
Asset Retirement Obligations [Line Items] | |||||
Asset retirement obligations at beginning of period | $ 1,810,674 | $ 1,775,792 | $ 1,775,792 | ||
Liabilities incurred or acquired | 1,868,276 | 672,339 | |||
Liabilities settled | (53,783) | (677,616) | |||
Accretion expense | 125,078 | 40,159 | |||
Asset retirement obligations at end of period | 3,750,245 | [1] | 1,810,674 | 3,750,245 | [1] |
Less: current asset retirement obligation (classified with accounts payable and accrued liabilities) | (300,000) | (547,000) | (300,000) | ||
Long-term asset retirement obligations | $ 3,450,245 | $ 1,263,674 | $ 3,450,245 | ||
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% | ||||
[1] | Asset retirement obligations represent the estimated fair value at June 30, 2016 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors. |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) | 12 Months Ended | ||||||
Jun. 30, 2016AUD | Jun. 30, 2015USD ($) | Jun. 30, 2014 | Jun. 30, 2016USD ($) | Jun. 30, 2015AUD | Jun. 30, 2015USD ($) | Jun. 30, 2011USD ($) | |
Income Taxes [Line Items] | |||||||
Tax losses carried forward | AUD 15,621,491 | $ 4,686,447 | AUD 13,316,288 | $ 3,994,887 | |||
Net operating tax losses | 61,688,535 | ||||||
Tax expense (benefit) | $ 3,021 | ||||||
Income tax allegedly due | $ 597,852 | ||||||
Internal Revenue Service (IRS) [Member] | |||||||
Income Taxes [Line Items] | |||||||
Net operating tax losses | 79,987,858 | ||||||
Limitation per year | 403,194 | ||||||
State and Local Jurisdiction [Member] | |||||||
Income Taxes [Line Items] | |||||||
Net operating tax losses | $ 46,216,143 | $ 29,217,044 | |||||
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, 2033 | ||||||
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, 2015USD ($) | |
Income Taxes [Abstract] | |
Current Federal | $ 2,821 |
Current State | 200 |
Current | 3,021 |
Total income tax provision (benefit) | $ 3,021 |
Income Taxes (Schedule Of Effec
Income Taxes (Schedule Of Effective Income tax Rate Reconciliation) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Jun. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Taxes [Abstract] | ||||
Federal statutory rate | 30.00% | |||
Income tax expense (benefit) at federal statutory rate | $ (3,790,398) | $ (10,984,983) | ||
State income taxes | (228,568) | (472,583) | ||
Alternative minimum tax | 2,821 | |||
Other adjustments - true up deferred balances | (498,257) | (1,101,884) | ||
Other - change in deferred tax rate | (188,080) | 60,666 | ||
Other | (550,957) | (1,562,773) | ||
Valuation allowance | $ 5,256,260 | 14,061,757 | ||
Income Tax Expense (Benefit), Total | $ 3,021 | $ 3,021 |
Income Taxes (Schedule Of Com54
Income Taxes (Schedule Of Components Of Deferred Tax Assets and (Liabilities)) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2013 |
Income Taxes [Abstract] | ||||
Net operating losses | $ 33,548,583 | $ 25,995,717 | ||
Asset retirement obligation | 1,395,262 | 458,869 | ||
Annual leave | 60,826 | 71,309 | ||
Abandonment limitation | 446,543 | 145,000 | ||
Accrued bonus | 64,789 | |||
Charitable contributions | 876 | 862 | ||
AMT Credit | 780,443 | 780,443 | ||
Share based compensation | 500,844 | 500,844 | ||
Derivative liability | 1,071,109 | |||
Valuation allowance | (33,337,136) | (28,080,876) | $ (28,080,876) | $ (14,019,119) |
Commodity liability | (94,588) | |||
Amortization - loan costs | ||||
Oil and gas property | (4,467,350) | |||
Net deferred income tax assets (liabilities) | ||||
Net current deferred tax asset | ||||
Noncurrent deferred tax liability |
Income Taxes (Summary Of Valuat
Income Taxes (Summary Of Valuation Allowance) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Income Taxes [Abstract] | ||
Balance | $ 28,080,876 | $ 28,080,876 |
Additions (reductions) to deferred income tax expense | 5,256,260 | 14,061,757 |
Balance | $ 33,337,136 | $ 28,080,876 |
Income Taxes (Reconciliation Of
Income Taxes (Reconciliation Of Gross Uncertain Tax Positions) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Income Taxes [Abstract] | ||
Total gross uncertain tax positions at beginning of year | $ 107,524 | |
Additions / Reductions for tax positions of prior years | ||
Additions / Reductions for tax positions of current year | ||
Reductions due to settlements with taxing authorities | (107,524) | |
Reductions due to lapse of statute of limitations | ||
Total amount of gross uncertain tax positions at end of year |
Capital Stock Contributed Equ57
Capital Stock Contributed Equity (Narrative) (Details) | 12 Months Ended | |||||
Jun. 30, 2016USD ($)AUD / shares$ / sharesshares | Jun. 30, 2015AUDAUD / sharesshares | Jun. 30, 2015$ / shares | Jun. 30, 2014AUDshares | Jun. 30, 2013USD ($)$ / shares | Jun. 30, 2012AUD / shares | |
Ordinary shares issued, shares | 378,020,400 | |||||
Ordinary shares issued, price per share | $ / shares | $ 0.0036 | |||||
Ordinary shares issued, amount | $ | $ 1,400,000 | |||||
Shares issued upon exercise of options, shares | 52,279 | 25,089 | ||||
Weighted average exercise price - cents (AUD), exercised | (per share) | $ 0.038 | AUD 0.038 | $ 0.028 | $ 0.035 | AUD 0.038 | |
Aggregate intrinsic value of options exercised | AUD (1,731) | AUD (592) | $ 880 | |||
1.5 Cents [Member] | ||||||
Shares issued upon exercise of options, shares | 52,279 | 25,089 |
Capital Stock Contributed Equ58
Capital Stock Contributed Equity (Contributed Equity) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
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) | $ 105,719,184 | $ 104,491,774 | |
Common stock outstanding and to be issued | 3,215,854,701 | 2,837,782,022 |
Capital Stock Contributed Equ59
Capital Stock Contributed Equity (Movements In Contributed Equity For The Year) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Capital Stock Contributed Equity [Abstract] | ||
Beginning Balance, shares | 2,837,782,022 | 2,837,756,933 |
Opening balance, value | $ 104,491,774 | $ 104,535,894 |
Capital raising, shares | 378,020,400 | |
Capital raising | $ 1,398,675 | |
Shares issued upon exercise of options, shares | 52,279 | 25,089 |
Shares issued upon exercise of options, value | $ 1,475 | $ 880 |
Transaction costs incurred, value | $ (172,740) | $ (45,000) |
Ending Balance, shares | 3,215,854,701 | 2,837,782,022 |
Shares on issue at balance date, value | $ 105,719,184 | $ 104,491,774 |
Cash Flow Statement (Details)
Cash Flow Statement (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||
Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2016 | Jun. 30, 2015 | |
Cash Flow Statement [Abstract] | ||||||||||
Net loss after tax | $ 2,822,938 | $ (1,944,025) | $ (2,538,571) | $ (10,974,251) | $ (21,162,785) | $ (1,944,025) | $ (2,538,571) | $ (10,974,251) | $ (12,633,909) | $ (36,619,632) |
Net (gain)/loss recognized on re-measurement to fair-value of investments held for trading | 2,644,244 | (673,859) | ||||||||
Depreciation | 4,766,949 | 6,920,945 | ||||||||
Accretion of asset retirement obligations | 125,078 | 40,159 | ||||||||
Borrowing costs | 185,138 | 135,694 | ||||||||
Exploration expense | 4,216,077 | 12,686,943 | ||||||||
Impairment losses of oil and gas properties | 11,029,442 | 21,475,450 | ||||||||
Abandonment expense | 404,485 | |||||||||
Gain on bargain purchase on acquisition | (10,775,231) | |||||||||
(Increase)/decrease in receivables | 1,648,678 | 667,223 | ||||||||
Increase/(decrease) in employee benefits | (24,917) | (10,897) | ||||||||
Increase/(decrease) in payables | 750,428 | (1,982,072) | ||||||||
Net Cash Provided by (Used in) Operating Activities, Continuing Operations, Total | $ 1,931,977 | $ 3,044,439 |
Credit Facility (Narrative) (De
Credit Facility (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||
Sep. 30, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Jan. 31, 2014 | |
Line of Credit Facility [Line Items] | |||||
Line of credit facility, maximum borrowing capacity | $ 25,000,000 | ||||
Line of credit facility, current borrowing capacity | $ 30,500,000 | ||||
Line of credit facility, amount outstanding | $ 30,500,000 | $ 18,699,000 | $ 6,000,000 | ||
Line of credit facility, expiration date | Oct. 31, 2017 | ||||
Debt instrument, interest rate at period end | 6.30% | ||||
Line of credity facility, cap on general and administrative expenditure | $ 3,000,000 | $ 6 | |||
Minimum hedging | 75 | ||||
Equity to be raised | $ 5 | 5,000,000 | |||
Debt paydown required | $ 11,500,000 | $ 10,000,000 | |||
London Interbank Offered Rate (LIBOR) [Member] | |||||
Line of Credit Facility [Line Items] | |||||
Debt instrument, basis spread on variable rate | 6.00% |
Credit Facility (Schedule of Cr
Credit Facility (Schedule of Credit Facilities) (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Credit Facility [Abstract] | ||
Credit facility at beginning of period | $ 18,699,000 | $ 6,000,000 |
Cash advanced under facility | 11,801,000 | 13,000,000 |
Proceeds from Issuance of Debt | 4,000,000 | |
Repayments | (301,000) | |
Credit facility at end of period | 30,500,000 | $ 18,699,000 |
Funds available for drawdown under the facility |
Share-Based Payments (Narrative
Share-Based Payments (Narrative) (Details) | 12 Months Ended | |||||
Jun. 30, 2016AUD / sharesshares | Jun. 30, 2015AUDAUD / sharesshares | Jun. 30, 2015$ / shares | Jun. 30, 2014AUDshares | Jun. 30, 2013USD ($)$ / shares | Jun. 30, 2012AUD / shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Exchange rate | 0.7680 | 0.9420 | ||||
Exercise price (Australian cents) | (per share) | AUD 0.038 | AUD 0.038 | $ 0.028 | $ 0.035 | AUD 0.038 | |
Options exercised | 52,279 | 25,089 | ||||
Aggregate intrinsic value of options exercised | AUD (1,731) | AUD (592) | $ 880 | |||
1.5 Cents [Member] | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Options exercised | 52,279 | 25,089 |
Share-Based Payments (Schedule
Share-Based Payments (Schedule Of Assumption Used In Black-Scholes Model) (Details) | 12 Months Ended | ||||
Jun. 30, 2016AUD / shares | Jun. 30, 2015AUD / shares | Jun. 30, 2015$ / shares | Jun. 30, 2013$ / shares | Jun. 30, 2012AUD / shares | |
Share-Based Payments [Abstract] | |||||
Exercise price (Australian cents) | (per share) | AUD 0.038 | AUD 0.038 | $ 0.028 | $ 0.035 | AUD 0.038 |
Share-Based Payments (Summary O
Share-Based Payments (Summary Of Stock Option Activity) (Details) | 12 Months Ended | |||||
Jun. 30, 2016AUDAUD / sharesshares | Jun. 30, 2015AUD / sharesshares | Jun. 30, 2015$ / sharesshares | Jun. 30, 2013$ / shares | Jun. 30, 2012AUD / shares | ||
Share-Based Payments [Abstract] | ||||||
Outstanding, start of period | 324,667,765 | 389,192,854 | 389,192,854 | |||
Exercised | (52,279) | (25,089) | (25,089) | |||
Cancelled/expired | (4,000,000) | (64,500,000) | (64,500,000) | |||
Outstanding, end of period | 320,615,486 | 324,667,765 | 324,667,765 | |||
Exercisable, end of period | 320,615,486 | 324,667,765 | 324,667,765 | |||
Weighted average exercise price - cents (AUD), outstanding, start of period | AUD / shares | AUD 0.038 | AUD 0.046 | ||||
Weighted average exercise price - cents (AUD), exercised | (per share) | 0.038 | 0.038 | $ 0.028 | $ 0.035 | AUD 0.038 | |
Weighted average exercise price - cents (AUD), cancelled/expired | AUD / shares | 0.155 | 0.090 | ||||
Weighted average exercise price - cents (AUD), outstanding, end of period | AUD / shares | 0.038 | 0.038 | ||||
Weighted average exercise price - cents (AUD), exercisable, end of period | AUD / shares | AUD 0.038 | AUD 0.038 | ||||
Aggregate intrinsic value of options - cents (AUD) | AUD | [1] | AUD (0.03) | ||||
[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. |
Share-Based Payments (Schedul66
Share-Based Payments (Schedule Of Additional Information Related To Options Outstanding) (Details) | 12 Months Ended | ||||||
Jun. 30, 2016AUD / sharesshares | Jun. 30, 2015AUD / sharesshares | Jun. 30, 2015AUD / shares$ / sharesshares | Jun. 30, 2013AUD / shares | Jun. 30, 2013$ / shares | Jun. 30, 2012AUD / shares | Jun. 30, 2014AUD / sharesshares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Exercise price (Australian cents) | (per share) | AUD 0.038 | AUD 0.038 | $ 0.028 | $ 0.035 | AUD 0.038 | ||
Options outstanding, number outstanding | shares | 320,615,486 | 324,667,765 | 324,667,765 | 389,192,854 | |||
Options outstanding, weighted average exercise prices | AUD 0.038 | AUD 0.038 | $ 0.038 | AUD 0.046 | |||
Options exercisable, number exercisable | shares | 320,615,486 | 324,667,765 | 324,667,765 | ||||
Options exercisable, weighted average exercise prices | AUD 0.038 | AUD 0.038 | $ 0.038 | ||||
3.8 Cents [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Exercise price (Australian cents) | AUD 0.038 | ||||||
Options outstanding, number outstanding | shares | 229,582,240 | ||||||
Options outstanding, weighted average remaining contractual life - years | 9 months | ||||||
Options outstanding, weighted average exercise prices | AUD 0.038 | ||||||
3.3 Cents [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Exercise price (Australian cents) | 0.033 | ||||||
Options outstanding, number outstanding | shares | 87,033,246 | ||||||
Options outstanding, weighted average remaining contractual life - years | 1 year 9 months 29 days | ||||||
Options outstanding, weighted average exercise prices | AUD 0.033 | ||||||
3.9 Cents [Member] | |||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||||||
Exercise price (Australian cents) | AUD 0.039 | ||||||
Options outstanding, number outstanding | shares | 4,000,000 | ||||||
Options outstanding, weighted average remaining contractual life - years | 1 year 5 months 1 day | ||||||
Options outstanding, weighted average exercise prices | AUD 0.039 |
Commitments (Narrative) (Detail
Commitments (Narrative) (Details) - USD ($) | 12 Months Ended | ||||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |||
Commitments [Abstract] | |||||
Operating leases, 2017 | [1] | $ 68,253 | |||
Operating leases, 2018 | [1] | 96,199 | |||
Operating leases, 2019 | [1] | 100,152 | |||
Operating Leases, 2020 | [1] | 103,616 | |||
Operating Leases, 2021 | [1] | 107,079 | |||
Operating leases, Thereafter | 8,947 | [1] | |||
Net rent expense | $ 157,094 | $ 139,599 | |||
[1] | Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Excludes variable rate debt interest payments related to the Company's credit facility. The interest rate is LIBOR plus 3.75% or approximately 6.3% at June 30, 2016. |
Commitments (Contractual Obliga
Commitments (Contractual Obligations) (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Commitments [Abstract] | |||||
Asset retirement obligations, Total | $ 3,750,245 | [1] | $ 1,810,674 | $ 1,775,792 | |
Asset retirement obligations, 2017 | [1] | 300,000 | |||
Asset retirement obligations, 2020 | [1] | ||||
Asset retirement obligations, 2021 | [1] | ||||
Asset retirement obligations, Thereafter | [1] | 3,450,245 | |||
Operating leases, Total | [2] | 484,246 | |||
Operating leases, 2017 | [2] | 68,253 | |||
Operating leases, 2018 | [2] | 96,199 | |||
Operating leases, 2019 | [2] | 100,152 | |||
Operating leases, 2020 | [2] | 103,616 | |||
Operating leases, 2021 | [2] | 107,079 | |||
Operating leases, Thereafter | 8,947 | [2] | |||
Credit Facility, Total | 30,500,000 | ||||
Credit Facility, 2017 | 11,500,000 | ||||
Credit Facility, 2018 | 19,000,000 | ||||
Credit Facility, 2020 | |||||
Credit Facility, 2021 | |||||
Payment of promissory note | 4,400,000 | ||||
Payment of Promissory Note TOTAL | 4,400,000 | ||||
Contractual Obligations, Total | 39,134,491 | ||||
Contractual Obligations, 2017 | 16,268,253 | ||||
Contractual Obligations, 2018 | 19,096,199 | ||||
Contractual Obligations, 2019 | 100,152 | ||||
Contractual Obligations, 2020 | 103,616 | ||||
Contractual Obligations, 2021 | 107,079 | ||||
Contractual Obligations, Thereafter | $ 3,459,192 | ||||
[1] | Asset retirement obligations represent the estimated fair value at June 30, 2016 of our obligations with respect to the retirement/abandonment of our oil and gas properties. Each reporting period the liability is accreted to its then present value. The ultimate settlement amount and the timing of the settlement of such obligations are unknown because they are subject to, among other things, federal, state, local, and tribal regulation and economic factors. | ||||
[2] | Leases relate primarily to obligations associated with our office facilities in Denver, Colorado and Perth, Western Australia. Excludes variable rate debt interest payments related to the Company's credit facility. The interest rate is LIBOR plus 3.75% or approximately 6.3% at June 30, 2016. |
Contingencies (Details)
Contingencies (Details) | Jun. 30, 2013USD ($) |
Contingencies [Abstract] | |
Contingent assets | |
Contingent liabilities |
Quarterly Financial Data (Detai
Quarterly Financial Data (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||
Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2016 | Jun. 30, 2015 | |
Quarterly Financial Data [Abstract] | ||||||||||
Revenues | $ 8,576,792 | $ 3,041,563 | $ 5,009,633 | $ 4,049,615 | $ 4,475,079 | $ 3,041,563 | $ 5,009,633 | $ 4,049,615 | $ 20,677,603 | $ 16,575,890 |
Income (loss) from continuing operations | 2,822,938 | (1,944,025) | (2,538,571) | (10,974,251) | (21,159,764) | (1,944,025) | (2,538,571) | (10,974,251) | (12,633,909) | (36,616,611) |
Income tax (provision)/benefit | (3,021) | (3,021) | ||||||||
Net loss | $ 2,822,938 | $ (1,944,025) | $ (2,538,571) | $ (10,974,251) | $ (21,162,785) | $ (1,944,025) | $ (2,538,571) | $ (10,974,251) | $ (12,633,909) | $ (36,619,632) |
Basic loss per common share - cents per share | $ 0.16 | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.70) | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.43) | $ (1.29) |
Diluted earnings per common share - cents per share | $ 0.16 | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.70) | $ (0.07) | $ (0.09) | $ (0.43) | $ (0.43) | $ (1.29) |
Supplemental Information On O71
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations (Narrative) (Details) | 12 Months Ended | |
Jun. 30, 2015$ / bbl$ / Mcf | Jun. 30, 2014$ / bbl$ / Mcf | |
Discount factor of future net cash flows | 10.00% | |
Oil [Member] | ||
12 month historical average price per barrel of oil | $ / bbl | 37.12 | 59.64 |
Natural Gas [Member] | ||
12 month historical average price per Mcf | $ / Mcf | 0.37 | 4.30 |
Supplemental Information On O72
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, 2016 | Jun. 30, 2015 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | ||
Development costs | $ 31,332,473 | $ 18,339,362 |
Exploration costs | 1,449,750 | |
Undeveloped capitalized acreage | 178,254 | 23,130 |
Total costs incurred | $ 31,510,727 | $ 19,812,242 |
Supplemental Information On O73
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, 2016MBoeMBblsbblMMcf | Jun. 30, 2015MBoeMBblsMMcf | |
Reserve Quantities [Line Items] | ||
Proved Developed Reserves ProductionBOE | MBoe | (335) | (269) |
Beginning of year (BOE) | MBoe | 1,483 | 1,773 |
Revisions of previous quantity estimates (BOE) | MBoe | 3,041 | (467) |
Extensions, discoveries and improved estimates (BOE) | MBoe | 446 | |
Acquisitions (BOE) | MBoe | 7,226 | |
End of year (BOE) | MBoe | 11,415 | 1,483 |
Proved developed producing reserves (BOE) | MBoe | 4,240 | 1,483 |
Proved undeveloped reserves (BOE) | MBoe | 5,905 | |
Proved Developed Non Producing (BOE) | MBoe | 1,270 | |
Proved reserves (BOE) | MBoe | 11,415 | 1,483 |
Oil [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of year (Volume) | MBbls | 1,285 | 1,478 |
Revisions of previous quantity estimates (Volume) | MBbls | 2,597 | (376) |
Extensions, discoveries and improved recovery (Volume) | MBbls | 414 | |
Acquisitions (Volume) | MBbls | 6,340 | |
Production (Volume) | MBbls | (240) | (231) |
End of year (Volume) | MBbls | 9,982 | 1,285 |
Proved developed producing reserves (Volume) | MBbls | 3,724 | 1,285 |
Proved Developed Non Producing (Volume) | bbl | 970 | |
Proved undeveloped reserves (Volume) | MBbls | 5,288 | |
Proved reserves (Volume) | MBbls | 9,982 | 1,285 |
Natural Gas [Member] | ||
Reserve Quantities [Line Items] | ||
Beginning of year (Volume) | MMcf | 1,183 | 1,763 |
Revisions of previous quantity estimates (Volume) | MMcf | 2,662 | (547) |
Extensions, discoveries and improved recovery (Volume) | MMcf | 193 | |
Acquisitions (Volume) | MMcf | 5,317 | |
Production (Volume) | MMcf | (569) | (226) |
End of year (Volume) | MMcf | 8,593 | 1,183 |
Proved developed producing reserves (Volume) | MMcf | 3,092 | 1,183 |
Proved Developed Non Producing (Volume) | MMcf | 1,800 | |
Proved undeveloped reserves (Volume) | MMcf | 3,701 | |
Proved reserves (Volume) | MMcf | 8,593 | 1,183 |
Supplemental Information On O74
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, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2013 | Jun. 30, 2012 |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | |||||
Future cash inflows | $ 373,740 | $ 72,900 | $ 148,975 | $ 133,589 | $ 71,655 |
Future production costs | (184,691) | (22,403) | (43,009) | (44,672) | (29,321) |
Future development costs | (50,752) | (38) | (12,461) | (29,012) | (10,198) |
Future income taxes | (21,819) | (12,050) | (5,524) | ||
Future net cashflows | 138,297 | 50,459 | 71,686 | 47,855 | 26,612 |
10% discount | (71,550) | (16,206) | (29,093) | (26,012) | (13,274) |
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total | $ 66,747 | $ 34,253 | $ 42,593 | $ 21,843 | $ 13,338 |
Supplemental Information On O75
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, 2016 | Jun. 30, 2015 | |
Supplemental Information On Oil And Natural Gas Exploration, Development And Production Activities, Inclusive Of Discontinued Operations [Abstract] | ||
Beginning of year | $ 34,253 | $ 42,593 |
Sales of oil and gas produced during the period, net of production costs | (3,575) | (7,178) |
Net changes in prices and production costs | (15,705) | (22,610) |
Previously estimated development costs incurred during the period | (1,898) | |
Changes in estimates of future development costs | (14,545) | |
Extensions, discoveries and improved recovery | 11,266 | |
Revisions of previous quantity estimates and other | 18,074 | (6,197) |
Purchase of reserves in place | 41,564 | |
Change in future income taxes | 11,809 | |
Accretion of discount | 3,452 | 5,440 |
Other | 3,229 | (2,768) |
Balance at end of year | $ 66,747 | $ 34,253 |