Lynden Energy 10-K 28 Sep 15 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Jun. 30, 2015	Sep. 24, 2015	Dec. 31, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	LVL
Entity Registrant Name	Lynden Energy Corp.
Entity Central Index Key	1,622,620
Current Fiscal Year End Date	--06-30
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		130,198,411
Entity Public Float			$ 52.7

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Current assets
Cash and cash equivalents	$ 8,748,008	$ 13,955,890
Trade and other receivables, net of allowance for doubtful accounts	1,660,135	3,143,017
Income taxes receivable	469,434	200,000
Prepaid expenses	50,613
Total current assets	10,928,190	17,298,907
Non-current assets
Property, plant and equipment	107,283,684	91,812,527
Total assets	118,211,874	109,111,434
Current liabilities
Trade and other payables	1,646,846	2,971,177
Income taxes payable		380,000
Total current liabilities	1,646,846	3,351,177
Non-current liabilities
Credit facility	29,908,366	17,853,245
Asset retirement liabilities	278,790	240,208
Deferred tax liabilities	17,497,692	14,902,811
Total non-current liabilities	47,684,848	32,996,264
Total liabilities	49,331,694	36,347,441
Shareholders' equity
Share capital-authorized unlimited common shares, no par value Issued and outstanding: June 30, 2015-130,198,411 June 30, 2014-129,275,911	65,622,727	65,160,387
Paid-in capital	15,228,879	15,434,128
Accumulated other comprehensive loss	(3,788,414)	(212,663)
Deficit	(8,183,012)	(7,617,859)
Total shareholders' equity	68,880,180	72,763,993
Total liabilities and shareholders' equity	$ 118,211,874	$ 109,111,434

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Jun. 30, 2015	Jun. 30, 2014
Statement of Financial Position [Abstract]
Common stock, no par value
Common stock, shares issued	130,198,411	129,275,911
Common stock, shares outstanding	130,198,411	129,275,911

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Revenue and other income
Petroleum and natural gas sales	$ 22,159,498	$ 29,366,595
Derivative financial instruments loss	(140,040)	(63,633)
Interest income	133,268	89,990
Total revenue and other income	22,152,726	29,392,952
Expenses
Production and operating expenses	(6,269,742)	(4,949,932)
Depletion, depreciation, and accretion	(10,232,732)	(7,917,230)
Exploration and impairments	(2,368,110)	(253,504)
General and administrative	(2,384,340)	(1,390,422)
Loss from equity investment	(431,919)
Interest	(549,672)	(283,183)
Total expenses	(22,236,515)	(14,794,271)
Other income
Gain on disposition of property, plant and equipment		10,219,755
Net (loss) income before income taxes	(83,789)	24,818,436
Income tax expense	(481,364)	(9,414,785)
Net (loss) income	(565,153)	15,403,651
Other comprehensive income (loss)
Foreign currency translation adjustment	(3,575,751)	(352,602)
Total comprehensive income (loss) for the year	$ (4,140,904)	$ 15,051,049
Weighted average number of common shares outstanding
Basic	130,045,582	123,798,574
Diluted	130,045,582	127,399,949
Net earnings per common share
Basic	$ 0	$ 0.12
Diluted	$ 0	$ 0.12

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating activities
Net (loss) income	$ (565,153)	$ 15,403,651
Adjustments for:
Accrued interest	55,121
Unrealized loss on derivative financial instruments	140,040	15,163
Depletion, depreciation and accretion	10,232,732	7,917,230
Impairments	2,372,281
Loss from equity investment	431,919
Share-based payments		55,683
Gain on disposition of property, plant and equipment		(10,219,755)
Deferred income taxes	627,230	8,554,735
Unrealized foreign exchange loss	(424,018)	(196,191)
Changes in non-cash working capital items:
Trade and other receivables	1,482,882	(545,806)
Current taxes receivable	(269,434)	(200,000)
Prepaid expenses	(50,613)
Trade and other payables	(123,269)	697,956
Income taxes payable	(380,000)	276,078
Cash generated by operating activities	13,529,718	21,758,744
Investing activities
Advances to investment in associate	(431,919)
Disposition of property, plant and equipment		20,803,912
Acquisition of property, plant and equipment	(29,378,690)	(34,235,029)
Cash used in investing activities	(29,810,609)	(13,431,117)
Financing activities
Drawings (repayments) of credit facility, net	12,000,000	(8,750,000)
Common shares issued for cash, net of issue costs	257,091	12,660,274
Cash generated by financing activities	12,257,091	3,910,274
Effect of exchange rate on cash held in foreign currency	(1,184,082)	(156,411)
Change in cash and cash equivalents during the year	(5,207,882)	12,081,490
Cash and cash equivalents, beginning of year	13,955,890	1,874,400
Cash and cash equivalents, end of year	8,748,008	13,955,890
Cash and cash equivalents are composed of:
Cash and cash equivalents, total	$ 13,955,890	$ 1,874,400

Consolidated Statements of Chan

Consolidated Statements of Changes In Shareholders' Equity - USD ($)	Total	Common Shares [Member]	Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Deficit [Member]
Total shareholders' equity		$ 49,279,688	$ 18,598,870	$ 139,939	$ (23,021,510)
Total shareholders' equity	$ 72,763,993	49,279,688	18,598,870	139,939	(23,021,510)
Beginning balance at Jun. 30, 2013		49,279,688	18,598,870	139,939	(23,021,510)
Common shares issued for cash:
Exercise of warrants		15,880,699	(3,220,425)
Foreign currency translation	(352,602)			(352,602)
Net (loss) income	15,403,651				15,403,651
Exercise of warrants		15,880,699	(3,220,425)
Share-based payments			55,683
Ending balance at Jun. 30, 2014	72,763,993	$ 65,160,387	15,434,128	(212,663)	(7,617,859)
Beginning balance, shares at Jun. 30, 2013		110,505,520
Common shares issued for cash:
Exercise of warrants, shares		18,770,391
Ending balance, shares at Jun. 30, 2014		129,275,911
Total shareholders' equity	72,763,993	$ 65,160,387	15,434,128	(212,663)	(7,617,859)
Total shareholders' equity	72,763,993	65,160,387	15,434,128	(212,663)	(7,617,859)
Common shares issued for cash:
Exercise of stock options		462,340	(205,249)
Exercise of stock options		462,340	(205,249)
Foreign currency translation	(3,575,751)			(3,575,751)
Net (loss) income	(565,153)				(565,153)
Ending balance at Jun. 30, 2015	$ 68,880,180	$ 65,622,727	15,228,879	(3,788,414)	(8,183,012)
Common shares issued for cash:
Exercise of stock options, shares	922,500	922,500
Ending balance, shares at Jun. 30, 2015		130,198,411
Total shareholders' equity	$ 68,880,180	$ 65,622,727	$ 15,228,879	$ (3,788,414)	$ (8,183,012)

Description of Business

Description of Business	12 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Description of Business	1. Description of Business Lynden Energy Corp. (the “ Company Business Corporations Act P&NG TSX-V

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Significant Accounting Policies	2. Significant Accounting Policies a) Basis of presentation These consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“ US GAAP b) Basis of consolidation The consolidated financial statements include the financial statements of the Company and its wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc. Investments where the Company has the ability to exercise significant influence are accounted for using the equity method. Under this method, the Company’s share of the associate’s earnings or losses is included in operations with a corresponding change in the carrying value of the investment. Dividends received from these investments are credited to the investment. The Company’s 48% interest in Abajo Gas Transmission Company, LLC is accounted for using the equity method (note 4). A substantial portion of the Company’s exploration, development and production activities is conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities. Inter-company balances and transactions, including income and expenses arising from inter-company transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee. c) Foreign currency translation The consolidated financial statements are presented in United States dollars, except where otherwise indicated, and all values are rounded to the nearest dollar, except where otherwise indicated. The individual financial statements of each entity are prepared in their functional currency, which is the currency of the primary economic environment in which the entity operates. The functional currency of the Company and its wholly owned subsidiary, Lynden Exploration Ltd., is the Canadian dollar. The functional currency of the Company’s wholly owned subsidiary, Lynden USA Inc., is the United States dollar. Transactions in foreign currencies are initially recorded into the entities’ functional currencies at the exchange rates at the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated using exchange rates prevailing at the date of the statement of financial position. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value is determined. Revenue and expense items are translated at the exchange rates in effect at the date of underlying transaction, except for items related to non-monetary assets and liabilities, which are translated at historical exchange rates. Exchange rate differences are recognized in the statement of income and comprehensive income in the period they arise. The results of the Company and Lynden Exploration Ltd. are translated to the United States dollar presentation currency as follows: all assets and liabilities are translated at the exchange rate prevailing at the statement of financial position date; equity balances are translated at the rates of exchange at the transaction dates. All items included in the statements of income (loss) and comprehensive income (loss) are translated using the average monthly exchange rates unless there are significant fluctuations in the exchange rate, in which case the rate at the date of transaction is used. All differences arising upon the translation to the presentation currency are recorded in the foreign currency translation reserve. d) Use of estimates The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amount and timing of recording of assets, liabilities, revenues and expenses since the determination of these amounts may be dependent on future events. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion, amortization and accretion (“ DDA&A e) Cash and cash equivalents Cash and cash equivalents in the statement of financial position comprise cash at banks and on hand, and short term deposits with an original maturity of three months or less, which are readily convertible into a known amount of cash. f) Trade and other receivables and allowance for doubtful accounts The majority of all revenues from the sale of oil and natural gas production are collected and disbursed on our behalf by CrownQuest Operating LLC (“ CrownQuest CrownRock g) Property, plant and equipment (“ PPE Property, plant and equipment are recorded at cost. The Company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The Company capitalizes exploratory well costs as an asset when the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project or when the well has found a sufficient quantity of reserves to justify its completion as a producing well. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Company’s wells and related equipment and facilities and are expensed as incurred. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Impairment analyses are based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually. Gains or losses on assets sold are included in the consolidated statement of income. h) Asset retirement liabilities The Company’s P&NG operating activities give rise to dismantling, decommissioning and site remediation activities. These obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to the initial obligation is added to the capitalized costs of the related asset. Amortization of capitalized decommissioning costs and increases in asset retirement obligations resulting from the passage of time are recorded as amortization and accretion, respectively, which are included in depreciation, depletion, amortization and accretion and charged against net income. Changes in the estimated liability resulting from revisions to the estimated timing or amount of cash flows, are recognized as a change in the asset retirement obligation and related capitalized asset retirement cost and are measured at fair value and discounted to present value. i) Revenue recognition The Company uses the accrual method of accounting for P&NG revenues. Sales of P&NG are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when P&NG has been delivered to a pipeline or oil hauling has occurred. Crude oil is priced on the average monthly settlement price during the calendar month of the delivery month based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of the Company’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. j) Share-based payments Employees (including directors and senior executives) of the Company may receive a portion of their remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (“ equity-settled transactions In situations where equity instruments are issued for goods or services, the transaction is measured at the fair value of the goods or services received by the entity. When the value of the goods or services cannot be specifically identified, they are measured at fair value of the share-based payment. The costs of equity-settled transactions with employees are measured by reference to the fair value at the date on which they are granted. The costs of equity-settled transactions are recognized, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (“ the vesting date No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are treated as vesting irrespective of whether or not the market condition is satisfied provided that all other performance and/or service conditions are satisfied. Where the terms of an equity-settled award are modified, the minimum expense recognized is the expense as if the terms had not been modified. An additional amount is recognized on the same basis as the amount of the original award for any modification which increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee as measured at the date of modification. The dilutive effect of outstanding options is reflected as additional dilution in the computation of earnings per share. k) Income tax Income tax expense is comprised of current and deferred income tax. Current income tax is the expected tax payable or refund on taxable income or loss for the year, using rates enacted at the reporting date. Deferred income tax is recognized using the liability method of accounting for income taxes. Under this method, deferred tax is recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted income tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax is recognized in net income except to the extent that it relates to items recognized directly in shareholders’ equity. Deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. The Company routinely reviews deferred tax assets and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. The Company recognizes the financial statement effects of an uncertain tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. The amount of tax benefit recognized is the largest amount of tax benefit that has a greater than 50 percent likelihood of being realized upon settlement with a taxation authority. The Company recognizes potential penalties and interest related to uncertain tax positions in income tax expense. The effect of changes in enacted income tax rates or laws, for both current and deferred income tax, is recognized in net income in the period of enactment. l) Financial assets All financial assets are initially recorded at fair value and classified upon inception into one of the following four categories: held to maturity, available-for-sale, loans and receivables or at fair value through profit or loss (“ FVTPL Financial assets classified as FVTPL are measured at fair value with unrealized gains and losses recognized through earnings. Financial assets classified as loans and receivables and held to maturity are measured at amortized cost using the effective interest method less any allowance for impairment. The effective interest method is a method of calculating the amortized cost of a financial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period. Financial assets classified as available-for-sale are measured at fair value with unrealized gains and losses recognized in other comprehensive income except for losses in value that are considered significant or prolonged decline in the fair value of that investment below its cost which are considered impairments resulting in a reclassification from other comprehensive income to earnings. Transactions costs associated with FVTPL financial assets are expensed as incurred, while transaction costs associated with all other financial assets are included in the initial carrying amount of the asset. m) Financial liabilities All financial liabilities are initially recorded at fair value and classified upon inception as FVTPL or other financial liabilities. Financial liabilities classified as other financial liabilities are initially recognized at fair value less directly attributable transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. The effective interest method is a method of calculating the amortized cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period. Financial liabilities classified as FVTPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as FVTPL. Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated as effective hedging instruments. Transaction costs on financial liabilities classified as FVTPL are expensed as incurred. Fair value changes on financial liabilities classified as FVTPL are recognized through the statement of income and comprehensive income. o) Net income (loss) per share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. For the diluted net income (loss) per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income (loss). The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all common share equivalents would be used to repurchase common shares at the average market price. p) Interest capitalization The Company capitalizes interest costs which are directly attributable to the acquisition or construction of qualifying assets. q) Recent accounting pronouncements As of July 1, 2014, the Company adopted the following Financial Accounting Standards Board (“ FASB • Accounting Standards Update 2013-04, Obligations resulting from Joint and Several Liability Arrangements • Accounting Standards Update 2013-05, Parent’s Accounting for Cumulative Translation Adjustments upon Derecognition of Certain Subsidiaries • Accounting Standards Update 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists The FASB has issued the following accounting standards updates which are not yet effective and which may have an impact on the Company: • Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity • Accounting Standards Update 2014-09, Revenue From Contracts With Customers • Accounting Standards Update 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period • Accounting Standards Update 2014-15, Disclosure of Uncertainties About an Entity’s Ability to Continue as a Going Concern The Company has not early adopted these accounting standards updates and is currently assessing the application of these standards on the results and financial position of the Company.

Trade and Other Receivables

Trade and Other Receivables	12 Months Ended
	Jun. 30, 2015
Receivables [Abstract]
Trade and Other Receivables	3. Trade and Other Receivables June 30, 2015 June 30, 2014 Accounts receivable – trade $ 1,340,803 $ 2,572,762 Accrued receivables 237,430 496,947 Sales taxes receivable 81,902 73,308 $ 1,660,135 $ 3,143,017 The Company did not have any allowance for doubtful accounts as at June 30, 2015 and 2014. As at June 30, 2015, $1,532,382 (2014—$2,991,585) is owing from one counterparty.

Investment in Associate

Investment in Associate	12 Months Ended
	Jun. 30, 2015
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Investment in Associate	4. Investment in Associate The Company has a 48% interest in a Utah, USA based natural gas transmission company, Abajo Gas Transmission Company, LLC (“ Abajo The Company exerts significant influence over Abajo as a result of its 48% interest. However, as a result of the Company’s partner holding a greater than 50% interest in Abajo and also acting as manager of Abajo, the Company does not control Abajo. As such, the investment in Abajo is accounted for using the equity method. At July 1, 2010, the Company wrote down its Abajo investment to $nil. The impairment charge was made after considering, among other things, the estimated future natural gas volumes to be transmitted by Abajo from the wells currently tied into the gas gathering system and the Company’s decision to not incur capital expenditures on the Paradox Basin Project in the near term. The following is summarized financial information for Abajo as at June 30, 2015 and June 30, 2014 and for the twelve month periods ended June 30, 2015 and 2014: June 30, June 30, Total assets $ 1,657,330 $ 1,682,118 Total liabilities $ 193,019 $ 861,934 Revenues $ 75,144 $ 88,617 Loss $ 331,017 $ 239,804 The Company’s cumulative share of losses attributable to Abajo from July 1, 2010 to June 30, 2015 that have not been recognized amounts to $4,731,583 and $152,285 (2014 – $148,959) for the year ended June 30, 2015. In March 2015, the Company advanced a further $431,919 to Abajo. This additional investment represents the funding of prior losses up to the amount of the additional investment and was expensed during the year ended June 30, 2015.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	5. Property, Plant and Equipment June 30, 2015 Cost Accumulated Net Book Value Petroleum and natural gas properties Proved $ 122,491,540 $ (23,096,935 ) $ 99,394,605 Exploratory well costs 36,938,662 (29,050,534 ) 7,888,128 159,430,202 (52,147,469 ) 107,282,733 Computer equipment 2,081 (1,130 ) 951 Total property, plant and equipment $ 159,432,283 $ (52,148,599 ) $ 107,283,684 June 30, 2014 Cost Accumulated Net Book Petroleum and natural gas properties Proved $ 100,407,384 $ (12,781,939 ) $ 87,625,445 Exploratory well costs 30,972,613 (26,786,552 ) 4,186,061 131,379,997 (39,568,491 ) 91,811,506 Computer Equipment 4,820 (3,799 ) 1,021 Total property, plant and equipment $ 131,384,817 $ (39,572,290 ) $ 91,812,527 The Company has pledged its interest in its property, plant and equipment to the issuer of its Credit Facility as security. Proved Petroleum and Natural Gas Assets Proved petroleum and natural gas assets consist of lease acquisition costs, costs of drilling and equipping development wells, and construction of related production facilities all relating to the Company’s Midland Basin property. In February 2014, the Company disposed of a 10.625% interest in 5 gross (1.53 net) vertical Midland Basin wells and underlying leases covering approximately 1,127 gross acres (345 acres net) for gross proceeds of $1.23 million, subject to customary post–closing adjustments. The Company recognized a gain of $305,000. The Company will receive a 20% working interest in new wells drilled on the lease by paying 24.375% of the drilling and completion costs. In December 2013, the Company disposed of 12 gross (4.7 net) vertical Midland Basin wells and underlying leases covering approximately 1,000 gross acres (403 acres net) for gross proceeds of $19.3 million, subject to customary post–closing adjustments. The Company recognized a gain of $10.2 million. Exploratory Well Costs Exploratory well costs consist of costs associated with the drilling and equipping of exploratory wells relating to 1) the Mitchell Ranch Project; 2) one vertical well location in the Midland Basin; and 3) one horizontal well location in the Midland Basin. Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project. Project costs suspended for longer than one year were primarily suspended pending the completion of economic evaluations including, but not limited to, results of additional appraisal drilling, well test analysis, additional geological and geophysical data, facilities and infrastructure development options, development plan approval, and permitting. If additional information becomes available that raises substantial doubt as to the economic or operational viability of any of these projects, the associated costs will be expensed at that time. The Company continues capitalization of exploratory well costs when the well has found 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. Paradox Basin Mitchell Ranch Wolfberry Total As at June 30, 2013 $ 445,706 $ 3,584,783 $ — $ 4,030,489 Additions pending the determination of proved reserves 22,652 151,737 — 174,389 Dispositions (18,817 ) — — (18,817 ) As at June 30, 2014 449,541 3,736,520 — 4,186,061 Additions pending the determination of proved reserves — 5,690,251 2,440,953 8,131,204 Reclassification to proved — — (2,165,155 ) (2,165,155 ) Impairments (449,541 ) (1,814,441 ) — (2,263,982 ) As at June 30, 2015 $ — $ 7,612,330 $ 275,798 $ 7,888,128 The following table provides an aging analysis of exploratory costs as at June 30, 2015 and 2014. June 30, June 30, Exploratory well costs capitalized for a period of one year or less $ 5,966,049 $ 174,389 Exploratory well costs capitalized for a period of one to two years 174,389 224,079 Exploratory well costs capitalized for a period of greater than three years 1,747,690 3,787,593 $ 7,888,128 $ 4,186,061 The majority of exploratory well costs capitalized for a period of greater than three years are lease acquisition costs. During the year ended June 30, 2015, the Company incurred an impairment charge of $1,814,441 for the Mitchell Ranch Project, of which $1,682,794 is for the Spade 17 #1 exploratory well. It was determined that all principal target zones in the Spade 17 #1 well had been tested and that no future completion operations were being planned. The Company had previously recognized cumulative income of $472,000 related to this well (2014: $82,000), which should have been applied to exploratory well costs. During the three months ended September 30, 2014, management determined that the capitalized costs related to the Paradox Basin Project suspended exploratory well costs should have been expensed in the year ended June 30, 2014, due to the lack of substantial activities to assess the reserves for more than one year following the drilling of the exploratory wells, and the lack of significant expenditures which are planned in the future. Management expensed the remaining costs as an immaterial out of period adjustment of $449,541 in the three months ended September 30, 2014. Management has determined that no prior period financial statements were materially misstated as a result of these costs. In December 2013, the Company disposed of its interest in leases covering approximately 8,400 acres in the Southern Prospect Area of the Paradox Basin for proceeds of approximately $307,000. The Company recognized a gain of approximately $288,000.

Trade and Other Payables

Trade and Other Payables	12 Months Ended
	Jun. 30, 2015
Payables and Accruals [Abstract]
Trade and Other Payables	6. Trade and Other Payables June 30, June 30, Accounts payable – trade $ 1,526,796 $ 2,693,097 Accrued liabilities $ 120,050 $ 278,080 $ 1,646,846 $ 2,971,177 As at June 30, 2015, $1,253,267 (2014 - $2,486,438) is due to one counterparty.

Credit Facility

Credit Facility	12 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Credit Facility	7. Credit Facility The Company has a reducing revolving line of credit (the “ Credit Facility The Credit Facility contains certain mandatory covenants, including minimum current ratio and cash flow requirements, and other standard business operating covenants. The Company has complied with all of these covenants as at and during the year ended June 30, 2015. The Company has pledged its interest in its P&NG and other assets as security for liabilities pursuant to the Credit Facility. Amounts owing on the Credit Facility are payable when the Credit Facility expires in August 2016, unless otherwise extended by the parties, or payable on demand on the event of default.

Asset Retirement Liabilities

Asset Retirement Liabilities	12 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Liabilities	8. Asset Retirement Liabilities The total decommissioning liabilities were estimated by management based on the Company’s net ownership interest in all wells, estimated costs to reclaim and abandon the wells and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation with weighted-average rate of 2%) to settle the decommissioning liabilities is approximately $4,189,000 as at June 30, 2015 (June 30, 2014—$3,579,000). These payments are expected to be made over the next 10 to 35 years. The Company used a weighted-average credit adjusted risk free rate of 10.2% to calculate the present value of the asset retirement liabilities. As at June 30, 2013 $ 200,531 Liabilities incurred 34,627 Property dispositions (13,941 ) Accretion 21,190 Revisions in estimated liabilities (2,199 ) As at June 30, 2014 240,208 Liabilities incurred 22,771 Liabilities settled (8,870 ) Accretion 25,297 Revisions in estimated liabilities (616 ) As at June 30, 2015 $ 278,790

Shareholders' Equity

Shareholders' Equity	12 Months Ended
	Jun. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Shareholders' Equity	9. Shareholders’ Equity a) Authorized share capital: An unlimited number of common shares without par value. An unlimited number of preference shares without par value. b) Warrants: The changes in warrants issued during the years ended June 30, 2015 and 2014 are as follows: Number of Weighted average As at June 30, 2013 27,415,760 $ 0.69 Exercised (18,770,391 ) $ 0.70 Expired (1,133,369 ) $ 0.70 As at June 30, 2014 7,512,000 $ 0.65 Expired (7,512,000 ) $ 0.65 As at June 30, 2015 — $ — c) Earnings per share: Diluted earnings per share computation June 30, June 30, Numerator: Net (loss) income $ (565,153 ) $ 15,403,651 Denominator: Weighted average number of common shares (basic) 130,045,582 123,798,574 Dilutive effect of share options — 1,626,501 Dilutive effect of warrants — 1,974,874 Weighted average number of common shares (diluted) 130,045,582 127,399,949 Diluted (loss) income per common share $ (0.00 ) $ 0.12 For the year ended June 30, 2015, there are nil (2014 – nil) warrants and 4,270,000 (2014 – 2,612,500) stock options that are not dilutive and have been excluded from the dilutive earnings per share calculation. d) Stock option plan The Company has a stock option plan whereby a maximum of 10% of the issued and outstanding common shares of the Company may be reserved for issuance pursuant to the exercise of stock options. The term of the stock options granted are fixed by the board of directors and are not to exceed ten years. The exercise prices of the stock options are determined by the board of directors but shall not be less than the closing price of the Company’s common shares on the day preceding the day on which the directors grant the stock options, less any discount permitted by the TSX-V. Subject to any vesting schedule imposed by the Company’s board of directors in respect of any specific stock option grants, the stock options vest immediately on the date of grant except for stock options granted to investor relations consultants which vest over a twelve month period. The Company did not grant or amend any stock options during the year ended June 30, 2015 and 2014. The Company recognized $55,683 for share-based payments in the year ended June 30, 2014 for stock options granted in prior years. The changes in stock options issued during the years ended June, 2015 and 2014 are as follows: Number of Weighted As at June 30, 2013 6,862,500 $ 0.61 Expired (230,000 ) $ 0.68 As at June 30, 2014 6,632,500 $ 0.61 Exercised (922,500 ) $ 0.31 Expired (1,440,000 ) $ 0.55 As at June 30, 2015 4,270,000 $ 0.69 For stock options exercised during the year ended June 30, 2015, the weighted average share price at the dates of exercise was CDN$0.92. The following table summarizes information about stock options outstanding and exercisable at June 30, 2015: Options outstanding Options exercisable Exercise price (CDN$) Number of Weighted Number of Weighted $0.50 to $0.60 1,657,500 1.70 1,657,500 1.70 $0.80 2,612,500 1.06 2,612,500 1.06 4,270,000 1.31 4,270,000 1.31

Related Party Transactions

Related Party Transactions	12 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	10. Related Party Transactions The Company incurred the following fees and expenses in the normal course of operations at amounts agreed upon between the parties to companies owned by key management and directors. The legal fees are paid to a law firm in which a director is a shareholder and the transportation and marketing costs are paid to Abajo Gas Transmission Company, LLC, the Company’s investment in associate. June 30, June 30, Legal fees $ 42,013 $ 38,972 Transportation and marketing costs 41,607 41,322 $ 83,620 $ 80,294 Trade and other payables include $33,320 (June 30, 2014—$47,104) owing to related parties. Amounts due to or from related parties are unsecured, non-interest bearing and are due on demand.

Financial Instruments

Financial Instruments	12 Months Ended
	Jun. 30, 2015
Investments, All Other Investments [Abstract]
Financial Instruments	11. Financial Instruments As at June 30, 2015, the Company’s financial instruments are cash and cash equivalents, trade and other receivables, credit facility, trade and other payables, and a commodity derivative liability. These financial instruments are classified as follows: Cash and cash equivalents – loans and receivables Trade and other receivables – loans and receivables Credit facility – other financial liabilities Trade and other payables – other financial liabilities Derivative liability – fair value through profit or loss The following fair value hierarchy is used to categorize and disclose the Company’s financial assets and liabilities held at fair value for which a valuation technique is used: Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities. Level 2: All inputs which have a significant effect on the fair value are observable, either directly or indirectly, for substantially the full contractual term. Level 3: Inputs which have a significant effect on the fair value are not based on observable market data. The Company’s commodity derivative liability was classified as a level 2 in accordance with the above hierarchy. The amounts reported in the statement of financial position for the Company’s cash and cash equivalents, trade and other receivables, credit facility, and trade and other payables are carrying amounts and approximate their fair values due to their short-term nature. The Company has exposure to credit risk, liquidity risk, and market risk from its use of financial instruments. a) Credit risk Credit risk is the risk that one party to a financial instrument will cause a financial loss for the other party by failing to discharge an obligation. The Company’s cash and cash equivalents and trade and other receivables are exposed to credit risk. Management believes the credit risk on cash is low because the counterparties are highly rated financial institutions. The majority of the Company’s trade and other receivables are with customers in the petroleum and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore the collection of trade and other receivables may be affected by changes in economic or other conditions. The Company believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of trade and other receivables to date and therefore has not made any provision for bad debts. The Company did not have any allowance for doubtful accounts as at June 30, 2015 and 2014. As at June 30, 2015, $1,532,385 (2014—$2,991,585) is owing from CrownQuest. The aging of trade and other receivables are as follows: June 30, June 30, Trade and other receivables 0 to 60 days $ 1,592,126 $ 3,083,365 61 to 120 days 8,357 6,762 > 120 days 1 59,652 52,890 $ 1,660,135 $ 3,143,017 1 Utah State withholding taxes on P&NG sales. b) Liquidity Risk Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities. The Company’s trade and other payables are generally payable within 90 days. The Company’s objective is to have sufficient capital to meet short term financial obligations after taking into account its exploration and development obligations, cash on hand, the unused borrowing base amount under its Credit Facility and anticipated changes in the Credit Facility borrowing base amount. Advances under the Credit Facility can be in the form of Eurodollar loans, which have a maximum period of 90 days, or in the form of floating rate loans, which can remain outstanding to the Credit Facility final maturity date of August 29, 2016. Eurodollar loans can be converted at the Company’s election to floating rate loans, or continued as new Eurodollar loans, provided that the total amount advanced under the Credit Facility does not exceed the borrowing base amount at that time. The Company’s continued investment in developing its property, plant and equipment would generally increase the amount of the borrowing base, however adverse exploration and development results or a decrease in the price of petroleum and natural gas would negatively impact the amount of the borrowing base. Repayments under the Credit Facility prior to the maturity date will be required only to the extent that outstanding principal and interest exceed the borrowing base. The following table details the Company’s expected remaining contractual maturities for its financial liabilities. The table is based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Company is required to satisfy the liabilities. Total Less than One to two More than Credit facility 1 $ 29,908,366 $ — $ 29,908,366 $ — Trade and other payables 1,646,846 1,646,846 — — Asset retirement obligation 4,189,000 — — 4,189,000 $ 35,744,212 $ 1,646,846 $ 29,908,366 $ 4,189,000 1 c) Market Risk Market risk is the risk of loss that may arise from changes in market factors such as interest rates, foreign exchange rates and commodity and equity prices. i) Interest Rate Risk Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Company’s cash and credit facility are exposed to interest rate risk as the Company invests cash at floating rates of interest in highly liquid instruments and it borrows funds at floating rates of interest. Fluctuations in interest rates impact interest income and expense. For the year ended June 30, 2015, if interest rates had been 1% higher, net loss and comprehensive loss would have been approximately $136,000 higher. If interest rates had been 1% lower, net loss and comprehensive loss would have been approximately $115,000 higher. ii) Currency Risk Currency risk is the risk that fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. Financial instruments that impact the Company’s earnings or loss due to currency fluctuations include Canadian dollar denominated assets and liabilities. The Company does not use derivative instruments or hedges to manage currency risks. The sensitivity of the Company’s earnings or loss due to changes in the exchange rate between the Canadian dollar and United States dollar is included in the table below: Cash Trade and Trade Net assets Effect of +/- Canadian dollar denomination $ 8,670,365 $ 8,196 $ (89,370 ) $ 8,589,191 $ 858,919 Based on the above net exposures at June 30, 2015, a 10% depreciation or appreciation of the Canadian dollar against the United States dollar would result in an increase or decrease, respectively, in the Company’s earnings by $858,919. iii) Price Risk The Company’s P&NG production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company’s cash flow from product sales will therefore be impacted by fluctuations in commodity prices. To protect future cash flows for planned capital expenditures, the Company periodically enters into commodity derivative contracts. In April 2015, the Company entered into a NYMEX based oil price put contract for 9,000 barrels of oil per month from September 2015 until August 2016 (12 months) with a strike price of $50 per barrel. Fair value changes on this contract are recognized in the statement of income. As at June 30, 2015, the Company has recognized an unrealized loss of $140,040. During the year ended June 30, 2014, the Company entered into costless collar oil commodity contracts. These costless collar contracts expired during the year ended June 30, 2014. Under the costless collar agreements, the Company would receive a cash payment if the average monthly price of West Texas Intermediate Crude Oil was below $80 and the Company would make a cash payment if the average monthly price of West Texas Intermediate Crude Oil was above $104 or $105. During the year ended June 30, 2014, the Company recognized a loss of $63,633.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Jun. 30, 2015
Supplemental Cash Flow Elements [Abstract]
Supplemental Cash Flow Information	12. Supplemental Cash Flow Information June 30, June 30, Non-cash financing activities: Fair value of stock options transferred to common shares on exercise of stock options $ 205,260 $ — Fair value of warrants transferred to common shares on exercise of warrants $ — $ 3,220,425 Additional cash flow information: Interest paid $ 917,052 $ 874,226 Taxes paid $ 503,668 $ 783,972

Segmented Information

Segmented Information	12 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Segmented Information	13. Segmented Information At June 30, 2015 the Company has one reportable operating segment, being the acquisition, exploration and development of petroleum and natural gas properties. The Company operates in two reportable geographic areas, being Canada and the United States of America. An operating segment is defined as a component of the Company: • that engages in business activities from which it may earn revenues and incur expenses; • whose operating results are reviewed regularly by the entity’s chief operating decision maker; and • for which discrete financial information is available. The Company’s revenues and capital assets in each of the geographic areas are as follows: Canada USA Consolidated Total Year ended June 30, 2015 2014 2015 2014 2015 2014 Revenue and other income Interest Income $ 133,268 $ 89,990 — — $ 133,268 $ 89,990 Petroleum sales, net of royalties — — 17,367,614 23,570,733 17,367,614 23,570,733 Natural gas sales, net of royalties — — 2,198,265 2,212,065 2,198,265 2,212,065 Natural gas liquids sales, net of royalties — — 2,593,619 3,583,797 2,593,619 3,583,797 $ 133,268 $ 89,990 $ 22,159,498 $ 29,366,595 $ 22,292,766 $ 29,456,585 Canada USA Consolidated Total June 30, June 30, June 30, June 30, June 30, June 30, Property, plant and equipment $ 951 $ 1,021 $ 107,282,733 $ 91,811,506 $ 107,283,684 $ 91,812,527

Income Taxes

Income Taxes	12 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	14. Income Taxes Income tax expense differs from the amount computed by applying the combined Canadian federal and provincial income tax rates, applicable to the Company, to the net earnings (loss) before income taxes due to the following: June 30, June 30, Net (loss) income before income taxes $ (83,789 ) $ 24,818,436 Combined statutory tax rate 26.00 % 26.00 % Income tax (recovery) expense computed at statutory tax rate (21,785 ) 6,452,793 Increase (decrease) attributable to: Changes in valuation allowance 3,499 214,513 Change in estimate 9,893 356,201 Non-deductible (taxable) expenditures 378,822 584,411 Effect of different statutory tax rates on earnings in subsidiaries 110,935 2,082,510 Equity investment taxable loss pick-up — (275,643 ) Income tax expense $ 481,364 $ 9,414,785 Current income tax expense (145,866 ) 860,050 Deferred income tax expense 627,230 8,554,735 Income tax expense $ 481,364 $ 9,414,785 Current income tax and deferred income tax for 2015 and 2014 are all US based taxes. The significant components of the Company’s deferred tax assets and liabilities are as follows: June 30, June 30, Deferred tax assets: Asset retirement liabilities $ 94,789 $ 81,671 Alternative minimum tax credits 272,830 272,830 Trade and other payables 47,614 — Credit facility 207,688 — Capital loss carry forwards — 17,669 Share issuance costs 2,106 31,315 Excess tax value of intangibles over book value 397 463 Excess tax value of property, plant and equipment over book value 681 1,136 Exploration and evaluation assets 599,091 673,948 Non-capital losses carry forwards 12,334,869 10,149,816 13,560,065 11,228,848 Valuation allowance (2,851,490 ) (2,847,991 ) 10,708,575 8,380,857 Deferred tax liabilities: Credit facility — (264,683 ) Unrealized mark-to-market gains (2,974,446 ) (1,006,795 ) Property, plant and equipment (25,231,821 ) (22,012,190 ) (28,206,267 ) (23,283,668 ) Net deferred tax assets (liabilities) $ (17,497,692 ) $ (14,902,811 ) The Company has income tax loss carry forwards of approximately $29,663,690 (2014 - $14,806,716) for US tax purposes. These recognized tax losses will expire between 2031 and 2035. The Company has unrecognized income tax loss carry forwards of approximately $8,650,700 (2014 - $7,289,792) for Canadian tax purposes. These unrecognized tax losses will expire between 2026 and 2035.

Subsequent Events

Subsequent Events	12 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	15. Subsequent Events Subsequent to June 30, 2015, 260,000 stock options with an exercise price of CDN$0.60 expired unexercised.

Supplemental Information on Oil

Supplemental Information on Oil and Gas Exploration and Production Activities	12 Months Ended
	Jun. 30, 2015
Extractive Industries [Abstract]
Supplemental Information on Oil and Gas Exploration and Production Activities	LYNDEN ENERGY CORP. Supplemental Information on Oil and Gas Exploration and Production Activities Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended June 30, 2015 and 2014: June 30, 2015 June 30, 2014 Property acquisition costs Proved $ 71,059 $ 24,948 Unproved 14,074 12,532 Exploration costs 5,951,975 415,361 Development costs 22,013,097 36,229,566 Total costs incurred $ 28,051,037 $ 36,682,407 All of the above costs were incurred in the United States of America. Exploratory Well Costs As of June 30, 2015, exploratory well costs consist of costs associated with the drilling and equipping of exploratory wells relating to 1) the Mitchell Ranch Project; 2) one vertical well location in the Midland Basin; and 3) one horizontal well location in the Midland Basin. On the Mitchell Ranch Project, the Company drilled and fracture stimulated an initial appraisal well, the Spade 17 #1, on the Mitchell Ranch Project in fiscal 2011. Periodic testing and further stimulation of the Spade 17 #1 well has been carried out since that time. In early-fiscal 2012 the Company entered into a 30 month term assignment for a large portion of its Mitchell Ranch Project acreage with a senior oil and gas company. The term assignment provided the Company an opportunity to observe the results of the senior oil and gas company’s drilling and completion activities on the Mitchell Ranch Project term assignment acreage and to incorporate their results in the Company’s testing plan for the Mitchell Ranch Project. On March 31, 2014 the senior oil and gas company elected to not continue with further activities and the term assignment acreage was returned, and the Company and its working interest partner actively resumed scheduling of additional testing activity, as described further below. In the third quarter of fiscal 2014 the Company and its working interest partner carried out a further round of testing on an uphole zone in the Spade 17 #1 well. During the year ended June 30, 2015, the Company incurred an impairment charge of $1,814,441 for the Mitchell Ranch Project, $1,682,794 of which is for the Spade 17 #1 well. It was determined that all principal target zones in the Spade 17 #1 well had been tested and that no future completion operations were being planned. Seismic interpretation and the initiation of a 3-D seismic program over a portion of the Mitchell Ranch Project acreage not previously covered by seismic was also carried out during fiscal 2014 and 2015 in preparation for drilling additional appraisal wells on the project. The Company and its working interest partner established plans for a four new well program to be carried out on the project. All four wells are in close proximity to the initial Spade 17#1 appraisal well which the Company expects will enhance operational efficiencies in the testing of the project. It is anticipated that the results from these wells will allow the Company to assess the reserves and the further potential development and viability of the project. Positive results would justify further major capital expenditures on the project. The first of the four wells was spud in late May 2014 and a first round of fracture stimulations was carried out in October 2014. The other three wells of the four well program were spud and drilled by October 2014, and several rounds of fracture stimulations and production testing have been carried out in the wells. There are several separate targeted zones that exhibit potential on the Mitchell Ranch Project. These zones will generally be tested by stimulating the lowermost zones in the well, observing flow-back from the stimulated zones, and once the production potential of the zones has been assessed move uphole to systematically test additional zones. Management anticipates that it will be able to determine the commerciality of the Mitchell Ranch Project by December 31, 2015. Also included in exploratory well costs are the costs incurred in preparation of drilling a vertical well in the Midland Basin that was spud shortly after June 30, 2015 and costs incurred for one horizontal well in the Midland Basin which was spud shortly before June 30, 2015. Both of these wells were drilled to their targeted depths and testing is underway. Management anticipates that it will be able to determine the commerciality of these wells by December 31, 2015. Standardized Measure of Discounted Future Net Cash Flows Reserve estimates and discounted future net cash flows are based on the unweighted average market prices for sales of oil and natural gas on the first calendar day of each month during the year. Cash flows are adjusted for transportation fees and regional price differentials, to the estimated future production of proved oil and natural gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties. Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs. The table below reflects the standardized measure of discounted future net cash flows related to the Company’s interest in proved reserves at June 30, 2015 and 2014. 2015 2014 Future cash flows $ 581,163,900 $ 488,770,334 Future production costs (179,031,200 ) (133,828,860 ) Future development costs (128,842,600 ) (64,661,351 ) Future income taxes (76,612,819 ) (86,035,972 ) Future net cash flows 196,677,281 204,244,151 Annual discount at 10% for estimated timing of cash flows (126,706,621 ) (121,768,244 ) Discounted future net cash flows $ 69,970,659 $ 82,475,908 Changes in Standardized Measure of Discounted Future Net Cash Flows The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended June 30, 2015 and 2014. June 30, 2015 June 30, 2014 Balance, beginning of year $ 82,475,908 $ 55,563,510 Changes resulting from: Sales of oil and gas produced, net of production costs (15,889,756 ) (24,416,663 ) Sales of reserves in place — (16,911,630 ) Discoveries and extensions 23,979,600 19,984,162 Changes in prices and production costs (42,421,155 ) 21,170,364 Changes in estimated future development costs (8,827,304 ) (26,847,805 ) Development costs incurred during the period 21,809,476 36,229,566 Revisions of previous quantity estimates (1,557,183 ) 15,765,294 Net change in income taxes 6,289,739 (13,484,610 ) Accretion of discount 11,169,119 7,129,418 Changes in production rates and other (7,057,785 ) 8,294,302 Net change (12,505,249 ) 26,912,398 Balance, end of year $ 69,970,659 $ 82,475,908 Oil and Gas Reserves The Company has presented the reserve estimates utilizing an oil price of $71.68 per Bbl and a natural gas price of $3.361 per MMBtu as of June 30, 2015, $100.27 per Bbl and $4.104 per MMBtu as of June 30, 2014, and $91.60 per Bbl and $3.459 per MMBtu as of June 30, 2013. The Company’s estimated reserves at June 30, 2015, June 30, 2014, and June 30, 2013 were based on reserve reports prepared by a third party engineer, Cawley, Gillespie & Associates, Inc. The proved oil and natural gas reserve estimates of the Company have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price. The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of third-party royalty interests, of natural gas, crude oil and condensate, and NGLs owned at year end. Natural gas volumes are in thousands of cubic feet (Mcf) at a pressure base of 14.73 pounds per square inch and volumes for oil are in barrels (Bbls). Total volumes are presented in barrels of oil equivalent (BOE). For this computation, one barrel is equivalent to 6,000 cubic feet of natural gas. The Company’s estimates of proved reserves are made using available production performance data, as well as pertinent geologic and reservoir data. These estimates are reviewed annually by an independent third party and revised, either upward or downward as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling. All of the Company’s reserves are located in Texas, USA. The following table provides a rollforward of the total proved reserves for the year ended June 30, 2015. Oil volumes are expressed in Bbls, natural gas volumes are expressed in Mcf, natural gas liquids volumes are expressed in Bbls, and total volumes are presented in BOE. Oil Natural Gas Natural Gas Total Net Proved Reserves Balance at June 30, 2014 3,950,079 9,719,125 1,928,080 7,498,013 Discoveries and extensions 3,086,400 8,595,200 1,528,700 6,047,633 Revisions of prior estimates (132,914 ) 1,927,264 147,833 336,130 Production (274,185 ) (670,309 ) (119,513 ) (505,416 ) Balance at June 30, 2015 6,629,380 19,571,280 3,485,100 13,376,360 Net Proved Developed Reserves, included above Balance at June 30, 2014 2,102,913 5,280,353 1,047,356 4,030,328 Balance at June 30, 2015 2,226,910 6,723,130 1,200,620 4,548,052 Net Proved Undeveloped Reserves, included above Balance at June 30, 2014 1,847,166 4,438,772 880,724 3,467,685 Balance at June 30, 2015 4,402,470 12,848,150 2,284,480 8,828,308 The following table provides a rollforward of the total proved reserves for the year ended June 30, 2014: Oil Natural Gas (1) Total Net Proved Reserves Balance at June 30, 2013 3,653,262 13,589,316 5,918,148 Discoveries and extensions 1,023,690 1,950,095 1,348,706 Revisions of prior estimates 327,408 9,377,971 1,890,403 Sales of reserves in place (808,114 ) (2,451,430 ) (1,216,686 ) Production (246,167 ) (1,178,347 ) (442,558 ) Balance at June 30, 2014 3,950,079 21,287,605 7,498,013 Net Proved Developed Reserves, included above Balance at June 30, 2013 1,805,485 6,585,058 2,902,995 Balance at June 30, 2014 2,102,913 11,564,489 4,030,328 Net Proved Undeveloped Reserves, included above Balance at June 30, 2013 1,847,777 7,004,258 3,015,153 Balance at June 30, 2014 1,847,166 9,723,116 3,467,685 (1) Natural gas reserves for fiscal 2013 are shown in “wet” Mcf, which includes NGL. We receive our production data from third-party operators. Our third-party operators did not and cannot provide complete three-stream data for fiscal 2013 that would allow the Company to break-out NGLs in addition to oil and gas in our reserve and production disclosure. The following is a discussion of the material changes in our proved reserve quantities for the years ended June 30, 2015 and 2014: Extensions and discoveries for 2015 were 6,047 MBoe, all of which are attributable to the drilling of vertical Midland Basin wells (Wolfberry) in the Permian Basin. During 2015 we produced 505 MBoe from these Wolfberry wells. Through our development drilling we increased the number of producing Wolfberry wells from 91 gross (37.18 net) wells to 109 gross (44.69 net) wells in 2015. We recorded positive revisions of prior estimates of 336 MBoe partially as a result of the better production history, and an overall improvement in average well performance. Extensions and discoveries for 2014 were 1,349 MBoe, all of which are attributable to the drilling of vertical Midland Basin wells (Wolfberry) in the Permian Basin. During 2014 we produced 442 MBoe from these Wolfberry wells. In December 2013, we sold 1,217 Mboe of proved reserves, including 554 MBoe of proved undeveloped reserves to BreitBurn Energy Partners L.P. After taking into account the sale to BreitBurn, through our development drilling we increased the number of producing Wolfberry wells from 67 gross (27.93 net) wells to 91 gross (37.18 net) wells in 2014. We recorded positive revisions of prior estimates of 1,890 MBoe partially as a result of the better production history, an overall improvement in average well performance, and higher oil and natural gas prices.

Significant Accounting Polici23

Significant Accounting Policies (Policies)	12 Months Ended
	Jun. 30, 2015
Accounting Policies [Abstract]
Basis of presentation	a) Basis of presentation These consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“ US GAAP
Basis of consolidation	b) Basis of consolidation The consolidated financial statements include the financial statements of the Company and its wholly owned subsidiaries, Lynden Exploration Ltd. and Lynden USA Inc. Investments where the Company has the ability to exercise significant influence are accounted for using the equity method. Under this method, the Company’s share of the associate’s earnings or losses is included in operations with a corresponding change in the carrying value of the investment. Dividends received from these investments are credited to the investment. The Company’s 48% interest in Abajo Gas Transmission Company, LLC is accounted for using the equity method (note 4). A substantial portion of the Company’s exploration, development and production activities is conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities. Inter-company balances and transactions, including income and expenses arising from inter-company transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee.
Foreign currency translation	c) Foreign currency translation The consolidated financial statements are presented in United States dollars, except where otherwise indicated, and all values are rounded to the nearest dollar, except where otherwise indicated. The individual financial statements of each entity are prepared in their functional currency, which is the currency of the primary economic environment in which the entity operates. The functional currency of the Company and its wholly owned subsidiary, Lynden Exploration Ltd., is the Canadian dollar. The functional currency of the Company’s wholly owned subsidiary, Lynden USA Inc., is the United States dollar. Transactions in foreign currencies are initially recorded into the entities’ functional currencies at the exchange rates at the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated using exchange rates prevailing at the date of the statement of financial position. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value is determined. Revenue and expense items are translated at the exchange rates in effect at the date of underlying transaction, except for items related to non-monetary assets and liabilities, which are translated at historical exchange rates. Exchange rate differences are recognized in the statement of income and comprehensive income in the period they arise. The results of the Company and Lynden Exploration Ltd. are translated to the United States dollar presentation currency as follows: all assets and liabilities are translated at the exchange rate prevailing at the statement of financial position date; equity balances are translated at the rates of exchange at the transaction dates. All items included in the statements of income (loss) and comprehensive income (loss) are translated using the average monthly exchange rates unless there are significant fluctuations in the exchange rate, in which case the rate at the date of transaction is used. All differences arising upon the translation to the presentation currency are recorded in the foreign currency translation reserve.
Use of estimates	d) Use of estimates The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the amount and timing of recording of assets, liabilities, revenues and expenses since the determination of these amounts may be dependent on future events. Significant estimates made by management include: oil and natural gas reserves and related present value of future cash flows, depreciation, depletion, amortization and accretion (“ DDA&A
Cash and cash equivalents	e) Cash and cash equivalents Cash and cash equivalents in the statement of financial position comprise cash at banks and on hand, and short term deposits with an original maturity of three months or less, which are readily convertible into a known amount of cash.
Trade and other receivables and allowance for doubtful accounts	f) Trade and other receivables and allowance for doubtful accounts The majority of all revenues from the sale of oil and natural gas production are collected and disbursed on our behalf by CrownQuest Operating LLC (“ CrownQuest CrownRock
Property, plant and equipment ("PPE")	g) Property, plant and equipment (“ PPE Property, plant and equipment are recorded at cost. The Company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized using the unit-of-production method. The Company capitalizes exploratory well costs as an asset when the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project or when the well has found a sufficient quantity of reserves to justify its completion as a producing well. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Company’s wells and related equipment and facilities and are expensed as incurred. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and gas reserves. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Unit-of-production depreciation is applied to those wells, plant and equipment assets associated with productive depletable properties, and the unit-of-production rates are based on the amount of proved developed reserves of oil and gas. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil and natural gas commodity prices. Annual volumes are based on field production profiles, which are also updated annually. Impairment analyses are based on reserve estimates used for internal planning and capital investment decisions. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset group would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount the carrying value exceeds fair value. Significant unproved properties are assessed for impairment individually and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually. Gains or losses on assets sold are included in the consolidated statement of income.
Asset retirement liabilities	h) Asset retirement liabilities The Company’s P&NG operating activities give rise to dismantling, decommissioning and site remediation activities. These obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to the initial obligation is added to the capitalized costs of the related asset. Amortization of capitalized decommissioning costs and increases in asset retirement obligations resulting from the passage of time are recorded as amortization and accretion, respectively, which are included in depreciation, depletion, amortization and accretion and charged against net income. Changes in the estimated liability resulting from revisions to the estimated timing or amount of cash flows, are recognized as a change in the asset retirement obligation and related capitalized asset retirement cost and are measured at fair value and discounted to present value.
Revenue recognition	i) Revenue recognition The Company uses the accrual method of accounting for P&NG revenues. Sales of P&NG are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when P&NG has been delivered to a pipeline or oil hauling has occurred. Crude oil is priced on the average monthly settlement price during the calendar month of the delivery month based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of the Company’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies.
Share-based payments	j) Share-based payments Employees (including directors and senior executives) of the Company may receive a portion of their remuneration in the form of share-based payment transactions, whereby employees render services as consideration for equity instruments (“ equity-settled transactions In situations where equity instruments are issued for goods or services, the transaction is measured at the fair value of the goods or services received by the entity. When the value of the goods or services cannot be specifically identified, they are measured at fair value of the share-based payment. The costs of equity-settled transactions with employees are measured by reference to the fair value at the date on which they are granted. The costs of equity-settled transactions are recognized, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (“ the vesting date No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are treated as vesting irrespective of whether or not the market condition is satisfied provided that all other performance and/or service conditions are satisfied. Where the terms of an equity-settled award are modified, the minimum expense recognized is the expense as if the terms had not been modified. An additional amount is recognized on the same basis as the amount of the original award for any modification which increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee as measured at the date of modification. The dilutive effect of outstanding options is reflected as additional dilution in the computation of earnings per share.
Income tax	k) Income tax Income tax expense is comprised of current and deferred income tax. Current income tax is the expected tax payable or refund on taxable income or loss for the year, using rates enacted at the reporting date. Deferred income tax is recognized using the liability method of accounting for income taxes. Under this method, deferred tax is recorded on the temporary differences between the accounting and income tax basis of assets and liabilities, using the enacted income tax rates expected to apply when the temporary differences are expected to reverse. Deferred tax is recognized in net income except to the extent that it relates to items recognized directly in shareholders’ equity. Deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. The Company routinely reviews deferred tax assets and a valuation allowance is provided if, after considering available evidence, it is more likely than not that a deferred tax asset will not be realized. The Company recognizes the financial statement effects of an uncertain tax position when it is more likely than not, based on technical merits, that the position will be sustained upon examination by a taxation authority. The amount of tax benefit recognized is the largest amount of tax benefit that has a greater than 50 percent likelihood of being realized upon settlement with a taxation authority. The Company recognizes potential penalties and interest related to uncertain tax positions in income tax expense. The effect of changes in enacted income tax rates or laws, for both current and deferred income tax, is recognized in net income in the period of enactment.
Financial assets	l) Financial assets All financial assets are initially recorded at fair value and classified upon inception into one of the following four categories: held to maturity, available-for-sale, loans and receivables or at fair value through profit or loss (“ FVTPL Financial assets classified as FVTPL are measured at fair value with unrealized gains and losses recognized through earnings. Financial assets classified as loans and receivables and held to maturity are measured at amortized cost using the effective interest method less any allowance for impairment. The effective interest method is a method of calculating the amortized cost of a financial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash receipts (including all fees and points paid or received that form an integral part of the effective interest rate, transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period. Financial assets classified as available-for-sale are measured at fair value with unrealized gains and losses recognized in other comprehensive income except for losses in value that are considered significant or prolonged decline in the fair value of that investment below its cost which are considered impairments resulting in a reclassification from other comprehensive income to earnings. Transactions costs associated with FVTPL financial assets are expensed as incurred, while transaction costs associated with all other financial assets are included in the initial carrying amount of the asset.
Financial liabilities	m) Financial liabilities All financial liabilities are initially recorded at fair value and classified upon inception as FVTPL or other financial liabilities. Financial liabilities classified as other financial liabilities are initially recognized at fair value less directly attributable transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. The effective interest method is a method of calculating the amortized cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period. Financial liabilities classified as FVTPL include financial liabilities held for trading and financial liabilities designated upon initial recognition as FVTPL. Derivatives, including separated embedded derivatives, are also classified as held for trading unless they are designated as effective hedging instruments. Transaction costs on financial liabilities classified as FVTPL are expensed as incurred. Fair value changes on financial liabilities classified as FVTPL are recognized through the statement of income and comprehensive income.
Net income (loss) per share	o) Net income (loss) per share Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. For the diluted net income (loss) per common share calculation, the weighted average number of shares outstanding is adjusted for the potential number of shares which may have a dilutive effect on net income (loss). The weighted average number of diluted shares is calculated in accordance with the treasury stock method which assumes that the proceeds received from the exercise of all common share equivalents would be used to repurchase common shares at the average market price.
Interest capitalization	p) Interest capitalization The Company capitalizes interest costs which are directly attributable to the acquisition or construction of qualifying assets.
Recent accounting pronouncements	q) Recent accounting pronouncements As of July 1, 2014, the Company adopted the following Financial Accounting Standards Board (“ FASB • Accounting Standards Update 2013-04, Obligations resulting from Joint and Several Liability Arrangements • Accounting Standards Update 2013-05, Parent’s Accounting for Cumulative Translation Adjustments upon Derecognition of Certain Subsidiaries • Accounting Standards Update 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists The FASB has issued the following accounting standards updates which are not yet effective and which may have an impact on the Company: • Accounting Standards Update 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity • Accounting Standards Update 2014-09, Revenue From Contracts With Customers • Accounting Standards Update 2014-12, Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could be Achieved After the Requisite Service Period • Accounting Standards Update 2014-15, Disclosure of Uncertainties About an Entity’s Ability to Continue as a Going Concern The Company has not early adopted these accounting standards updates and is currently assessing the application of these standards on the results and financial position of the Company.

Trade and Other Receivables (Ta

Trade and Other Receivables (Tables)	12 Months Ended
	Jun. 30, 2015
Receivables [Abstract]
Summary of Trade and Other Receivables	June 30, 2015 June 30, 2014 Accounts receivable – trade $ 1,340,803 $ 2,572,762 Accrued receivables 237,430 496,947 Sales taxes receivable 81,902 73,308 $ 1,660,135 $ 3,143,017

Investment in Associate (Tables

Investment in Associate (Tables)	12 Months Ended
	Jun. 30, 2015
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Summarized Financial Information	The following is summarized financial information for Abajo as at June 30, 2015 and June 30, 2014 and for the twelve month periods ended June 30, 2015 and 2014: June 30, June 30, Total assets $ 1,657,330 $ 1,682,118 Total liabilities $ 193,019 $ 861,934 Revenues $ 75,144 $ 88,617 Loss $ 331,017 $ 239,804

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
Summary of Property, Plant and Equipment	June 30, 2015 Cost Accumulated Net Book Value Petroleum and natural gas properties Proved $ 122,491,540 $ (23,096,935 ) $ 99,394,605 Exploratory well costs 36,938,662 (29,050,534 ) 7,888,128 159,430,202 (52,147,469 ) 107,282,733 Computer equipment 2,081 (1,130 ) 951 Total property, plant and equipment $ 159,432,283 $ (52,148,599 ) $ 107,283,684 June 30, 2014 Cost Accumulated Net Book Petroleum and natural gas properties Proved $ 100,407,384 $ (12,781,939 ) $ 87,625,445 Exploratory well costs 30,972,613 (26,786,552 ) 4,186,061 131,379,997 (39,568,491 ) 91,811,506 Computer Equipment 4,820 (3,799 ) 1,021 Total property, plant and equipment $ 131,384,817 $ (39,572,290 ) $ 91,812,527
Summary of Capitalization of Exploratory Well Costs	The Company continues capitalization of exploratory well costs when the well has found 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. Paradox Basin Mitchell Ranch Wolfberry Total As at June 30, 2013 $ 445,706 $ 3,584,783 $ — $ 4,030,489 Additions pending the determination of proved reserves 22,652 151,737 — 174,389 Dispositions (18,817 ) — — (18,817 ) As at June 30, 2014 449,541 3,736,520 — 4,186,061 Additions pending the determination of proved reserves — 5,690,251 2,440,953 8,131,204 Reclassification to proved — — (2,165,155 ) (2,165,155 ) Impairments (449,541 ) (1,814,441 ) — (2,263,982 ) As at June 30, 2015 $ — $ 7,612,330 $ 275,798 $ 7,888,128
Summary of Aging Analysis of Exploratory Costs	The following table provides an aging analysis of exploratory costs as at June 30, 2015 and 2014. June 30, June 30, Exploratory well costs capitalized for a period of one year or less $ 5,966,049 $ 174,389 Exploratory well costs capitalized for a period of one to two years 174,389 224,079 Exploratory well costs capitalized for a period of greater than three years 1,747,690 3,787,593 $ 7,888,128 $ 4,186,061

Trade and Other Payables (Table

Trade and Other Payables (Tables)	12 Months Ended
	Jun. 30, 2015
Payables and Accruals [Abstract]
Summary of Trade and Other Payables	June 30, June 30, Accounts payable – trade $ 1,526,796 $ 2,693,097 Accrued liabilities $ 120,050 $ 278,080 $ 1,646,846 $ 2,971,177

Asset Retirement Liabilities (T

Asset Retirement Liabilities (Tables)	12 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Changes in Asset Retirement Liabilities	The Company used a weighted-average credit adjusted risk free rate of 10.2% to calculate the present value of the asset retirement liabilities. As at June 30, 2013 $ 200,531 Liabilities incurred 34,627 Property dispositions (13,941 ) Accretion 21,190 Revisions in estimated liabilities (2,199 ) As at June 30, 2014 240,208 Liabilities incurred 22,771 Liabilities settled (8,870 ) Accretion 25,297 Revisions in estimated liabilities (616 ) As at June 30, 2015 $ 278,790

Shareholders' Equity (Tables)

Shareholders' Equity (Tables)	12 Months Ended
	Jun. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Changes in Warrants Issued	The changes in warrants issued during the years ended June 30, 2015 and 2014 are as follows: Number of Weighted average As at June 30, 2013 27,415,760 $ 0.69 Exercised (18,770,391 ) $ 0.70 Expired (1,133,369 ) $ 0.70 As at June 30, 2014 7,512,000 $ 0.65 Expired (7,512,000 ) $ 0.65 As at June 30, 2015 — $ —
Computation of Diluted Earning Per Share	Diluted earnings per share computation June 30, June 30, Numerator: Net (loss) income $ (565,153 ) $ 15,403,651 Denominator: Weighted average number of common shares (basic) 130,045,582 123,798,574 Dilutive effect of share options — 1,626,501 Dilutive effect of warrants — 1,974,874 Weighted average number of common shares (diluted) 130,045,582 127,399,949 Diluted (loss) income per common share $ (0.00 ) $ 0.12
Schedule of Changes in Stock Option Issued	The changes in stock options issued during the years ended June, 2015 and 2014 are as follows: Number of Weighted As at June 30, 2013 6,862,500 $ 0.61 Expired (230,000 ) $ 0.68 As at June 30, 2014 6,632,500 $ 0.61 Exercised (922,500 ) $ 0.31 Expired (1,440,000 ) $ 0.55 As at June 30, 2015 4,270,000 $ 0.69
Summary of Stock Options Outstanding and Exercisable	The following table summarizes information about stock options outstanding and exercisable at June 30, 2015: Options outstanding Options exercisable Exercise price (CDN$) Number of Weighted Number of Weighted $0.50 to $0.60 1,657,500 1.70 1,657,500 1.70 $0.80 2,612,500 1.06 2,612,500 1.06 4,270,000 1.31 4,270,000 1.31

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Summary of Fees and Expenses to Related Parties	The Company incurred the following fees and expenses in the normal course of operations at amounts agreed upon between the parties to companies owned by key management and directors. The legal fees are paid to a law firm in which a director is a shareholder and the transportation and marketing costs are paid to Abajo Gas Transmission Company, LLC, the Company’s investment in associate. June 30, June 30, Legal fees $ 42,013 $ 38,972 Transportation and marketing costs 41,607 41,322 $ 83,620 $ 80,294

Financial Instruments (Tables)

Financial Instruments (Tables)	12 Months Ended
	Jun. 30, 2015
Investments, All Other Investments [Abstract]
Summary of Aging of Trade and Other Receivables	The aging of trade and other receivables are as follows: June 30, June 30, Trade and other receivables 0 to 60 days $ 1,592,126 $ 3,083,365 61 to 120 days 8,357 6,762 > 120 days 1 59,652 52,890 $ 1,660,135 $ 3,143,017 1 Utah State withholding taxes on P&NG sales.
Summary of Expected Remaining Contractual Maturities for Financial Liabilities	The following table details the Company’s expected remaining contractual maturities for its financial liabilities. The table is based on the undiscounted cash flows of financial liabilities based on the earliest date on which the Company is required to satisfy the liabilities. Total Less than One to two More than Credit facility 1 $ 29,908,366 $ — $ 29,908,366 $ — Trade and other payables 1,646,846 1,646,846 — — Asset retirement obligation 4,189,000 — — 4,189,000 $ 35,744,212 $ 1,646,846 $ 29,908,366 $ 4,189,000 1
Summary of Currency Risk	The sensitivity of the Company’s earnings or loss due to changes in the exchange rate between the Canadian dollar and United States dollar is included in the table below: Cash Trade and Trade Net assets Effect of +/- Canadian dollar denomination $ 8,670,365 $ 8,196 $ (89,370 ) $ 8,589,191 $ 858,919

Supplemental Cash Flow Inform32

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Jun. 30, 2015
Supplemental Cash Flow Elements [Abstract]
Summary of Supplemental Cash Flow Information	12. Supplemental Cash Flow Information June 30, June 30, Non-cash financing activities: Fair value of stock options transferred to common shares on exercise of stock options $ 205,260 $ — Fair value of warrants transferred to common shares on exercise of warrants $ — $ 3,220,425 Additional cash flow information: Interest paid $ 917,052 $ 874,226 Taxes paid $ 503,668 $ 783,972

Segmented Information (Tables)

Segmented Information (Tables)	12 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Schedule of Revenues and Capital Assets	The Company’s revenues and capital assets in each of the geographic areas are as follows: Canada USA Consolidated Total Year ended June 30, 2015 2014 2015 2014 2015 2014 Revenue and other income Interest Income $ 133,268 $ 89,990 — — $ 133,268 $ 89,990 Petroleum sales, net of royalties — — 17,367,614 23,570,733 17,367,614 23,570,733 Natural gas sales, net of royalties — — 2,198,265 2,212,065 2,198,265 2,212,065 Natural gas liquids sales, net of royalties — — 2,593,619 3,583,797 2,593,619 3,583,797 $ 133,268 $ 89,990 $ 22,159,498 $ 29,366,595 $ 22,292,766 $ 29,456,585 Canada USA Consolidated Total June 30, June 30, June 30, June 30, June 30, June 30, Property, plant and equipment $ 951 $ 1,021 $ 107,282,733 $ 91,811,506 $ 107,283,684 $ 91,812,527

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	Income tax expense differs from the amount computed by applying the combined Canadian federal and provincial income tax rates, applicable to the Company, to the net earnings (loss) before income taxes due to the following: June 30, June 30, Net (loss) income before income taxes $ (83,789 ) $ 24,818,436 Combined statutory tax rate 26.00 % 26.00 % Income tax (recovery) expense computed at statutory tax rate (21,785 ) 6,452,793 Increase (decrease) attributable to: Changes in valuation allowance 3,499 214,513 Change in estimate 9,893 356,201 Non-deductible (taxable) expenditures 378,822 584,411 Effect of different statutory tax rates on earnings in subsidiaries 110,935 2,082,510 Equity investment taxable loss pick-up — (275,643 ) Income tax expense $ 481,364 $ 9,414,785 Current income tax expense (145,866 ) 860,050 Deferred income tax expense 627,230 8,554,735 Income tax expense $ 481,364 $ 9,414,785
Schedule of Significant Components of Deferred Tax Assets and Liabilities	The significant components of the Company’s deferred tax assets and liabilities are as follows: June 30, June 30, Deferred tax assets: Asset retirement liabilities $ 94,789 $ 81,671 Alternative minimum tax credits 272,830 272,830 Trade and other payables 47,614 — Credit facility 207,688 — Capital loss carry forwards — 17,669 Share issuance costs 2,106 31,315 Excess tax value of intangibles over book value 397 463 Excess tax value of property, plant and equipment over book value 681 1,136 Exploration and evaluation assets 599,091 673,948 Non-capital losses carry forwards 12,334,869 10,149,816 13,560,065 11,228,848 Valuation allowance (2,851,490 ) (2,847,991 ) 10,708,575 8,380,857 Deferred tax liabilities: Credit facility — (264,683 ) Unrealized mark-to-market gains (2,974,446 ) (1,006,795 ) Property, plant and equipment (25,231,821 ) (22,012,190 ) (28,206,267 ) (23,283,668 ) Net deferred tax assets (liabilities) $ (17,497,692 ) $ (14,902,811 )

Supplemental Information on O35

Supplemental Information on Oil and Gas Exploration and Production Activities (Tables)	12 Months Ended
	Jun. 30, 2015
Extractive Industries [Abstract]
Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities	Costs incurred in oil and natural gas property acquisition and development activities are as follows for the years ended June 30, 2015 and 2014: June 30, 2015 June 30, 2014 Property acquisition costs Proved $ 71,059 $ 24,948 Unproved 14,074 12,532 Exploration costs 5,951,975 415,361 Development costs 22,013,097 36,229,566 Total costs incurred $ 28,051,037 $ 36,682,407
Standardized Measure of Discounted Future Net Cash Flows	The table below reflects the standardized measure of discounted future net cash flows related to the Company’s interest in proved reserves at June 30, 2015 and 2014. 2015 2014 Future cash flows $ 581,163,900 $ 488,770,334 Future production costs (179,031,200 ) (133,828,860 ) Future development costs (128,842,600 ) (64,661,351 ) Future income taxes (76,612,819 ) (86,035,972 ) Future net cash flows 196,677,281 204,244,151 Annual discount at 10% for estimated timing of cash flows (126,706,621 ) (121,768,244 ) Discounted future net cash flows $ 69,970,659 $ 82,475,908
Changes in Standardized Measure of Discounted Future Net Cash Flows	The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended June 30, 2015 and 2014. June 30, 2015 June 30, 2014 Balance, beginning of year $ 82,475,908 $ 55,563,510 Changes resulting from: Sales of oil and gas produced, net of production costs (15,889,756 ) (24,416,663 ) Sales of reserves in place — (16,911,630 ) Discoveries and extensions 23,979,600 19,984,162 Changes in prices and production costs (42,421,155 ) 21,170,364 Changes in estimated future development costs (8,827,304 ) (26,847,805 ) Development costs incurred during the period 21,809,476 36,229,566 Revisions of previous quantity estimates (1,557,183 ) 15,765,294 Net change in income taxes 6,289,739 (13,484,610 ) Accretion of discount 11,169,119 7,129,418 Changes in production rates and other (7,057,785 ) 8,294,302 Net change (12,505,249 ) 26,912,398 Balance, end of year $ 69,970,659 $ 82,475,908
Summary of Net Proved and Proved Developed Reserve	The following table provides a rollforward of the total proved reserves for the year ended June 30, 2015. Oil volumes are expressed in Bbls, natural gas volumes are expressed in Mcf, natural gas liquids volumes are expressed in Bbls, and total volumes are presented in BOE. Oil Natural Gas Natural Gas Total Net Proved Reserves Balance at June 30, 2014 3,950,079 9,719,125 1,928,080 7,498,013 Discoveries and extensions 3,086,400 8,595,200 1,528,700 6,047,633 Revisions of prior estimates (132,914 ) 1,927,264 147,833 336,130 Production (274,185 ) (670,309 ) (119,513 ) (505,416 ) Balance at June 30, 2015 6,629,380 19,571,280 3,485,100 13,376,360 Net Proved Developed Reserves, included above Balance at June 30, 2014 2,102,913 5,280,353 1,047,356 4,030,328 Balance at June 30, 2015 2,226,910 6,723,130 1,200,620 4,548,052 Net Proved Undeveloped Reserves, included above Balance at June 30, 2014 1,847,166 4,438,772 880,724 3,467,685 Balance at June 30, 2015 4,402,470 12,848,150 2,284,480 8,828,308 The following table provides a rollforward of the total proved reserves for the year ended June 30, 2014: Oil Natural Gas (1) Total Net Proved Reserves Balance at June 30, 2013 3,653,262 13,589,316 5,918,148 Discoveries and extensions 1,023,690 1,950,095 1,348,706 Revisions of prior estimates 327,408 9,377,971 1,890,403 Sales of reserves in place (808,114 ) (2,451,430 ) (1,216,686 ) Production (246,167 ) (1,178,347 ) (442,558 ) Balance at June 30, 2014 3,950,079 21,287,605 7,498,013 Net Proved Developed Reserves, included above Balance at June 30, 2013 1,805,485 6,585,058 2,902,995 Balance at June 30, 2014 2,102,913 11,564,489 4,030,328 Net Proved Undeveloped Reserves, included above Balance at June 30, 2013 1,847,777 7,004,258 3,015,153 Balance at June 30, 2014 1,847,166 9,723,116 3,467,685 (1) Natural gas reserves for fiscal 2013 are shown in “wet” Mcf, which includes NGL. We receive our production data from third-party operators. Our third-party operators did not and cannot provide complete three-stream data for fiscal 2013 that would allow the Company to break-out NGLs in addition to oil and gas in our reserve and production disclosure.

Significant Accounting Polici36

Significant Accounting Policies - Additional Information (Detail)	Jun. 30, 2015
Abajo Gas Transmission Company, LLC [Member]
Significant Accounting Policies [Line Items]
Ownership interest percentage	48.00%

Trade and Other Receivables - S

Trade and Other Receivables - Summary of Trade and Other Receivables (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Receivables [Abstract]
Accounts receivable - trade	$ 1,340,803	$ 2,572,762
Accrued receivables	237,430	496,947
Sales taxes receivable	81,902	73,308
Total	$ 1,660,135	$ 3,143,017

Trade and Other Receivables - A

Trade and Other Receivables - Additional Information (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Receivables [Abstract]
Allowance for doubtful accounts	$ 0	$ 0
Accounts receivable owed from one counterparty	$ 1,532,382	$ 2,991,585

Investment in Associate - Addit

Investment in Associate - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended		60 Months Ended
	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jul. 01, 2010
Investments in and Advances to Affiliates [Line Items]
Investment in associate		$ 431,919
Abajo Gas Transmission Company, LLC [Member]
Investments in and Advances to Affiliates [Line Items]
Ownership interest percentage		48.00%		48.00%
Investment written off					$ 0
Investment in associate	$ 431,919
Amount of cumulative share of losses not recognized		$ 152,285	$ 148,959	$ 4,731,583
Abajo Gas Transmission Company, LLC [Member] | Minimum [Member]
Investments in and Advances to Affiliates [Line Items]
Ownership interest percentage		50.00%		50.00%

Investment in Associate - Summa

Investment in Associate - Summarized Financial Information (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Financial Information [Line Items]
Total assets	$ 118,211,874	$ 109,111,434
Total liabilities	49,331,694	36,347,441
Revenues	22,152,726	29,392,952
Loss	(565,153)	15,403,651
Abajo Gas Transmission Company, LLC [Member]
Financial Information [Line Items]
Total assets	1,657,330	1,682,118
Total liabilities	193,019	861,934
Revenues	75,144	88,617
Loss	$ 331,017	$ 239,804

Property, Plant and Equipment -

Property, Plant and Equipment - Summary of Property, Plant and Equipment (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Property, Plant and Equipment [Line Items]
Property plant and equipment, cost	$ 159,432,283	$ 131,384,817
Property plant and equipment, Accumulated Depletion, Depreciation and Impairment	(52,148,599)	(39,572,290)
Property plant and equipment, net	107,283,684	91,812,527
Petroleum and Natural Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, cost	159,430,202	131,379,997
Property plant and equipment, Accumulated Depletion, Depreciation and Impairment	(52,147,469)	(39,568,491)
Property plant and equipment, net	107,282,733	91,811,506
Computer Equipment [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, cost	2,081	4,820
Property plant and equipment, Accumulated Depletion, Depreciation and Impairment	(1,130)	(3,799)
Property plant and equipment, net	951	1,021
Proved [Member] | Petroleum and Natural Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, cost	122,491,540	100,407,384
Property plant and equipment, Accumulated Depletion, Depreciation and Impairment	(23,096,935)	(12,781,939)
Property plant and equipment, net	99,394,605	87,625,445
Exploratory Well Costs [Member] | Petroleum and Natural Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, cost	36,938,662	30,972,613
Property plant and equipment, Accumulated Depletion, Depreciation and Impairment	(29,050,534)	(26,786,552)
Property plant and equipment, net	$ 7,888,128	$ 4,186,061

Property, Plant and Equipment42

Property, Plant and Equipment - Additional Information (Detail)	1 Months Ended		3 Months Ended	12 Months Ended
	Feb. 28, 2014USD ($)aWells	Dec. 31, 2013USD ($)aWells	Sep. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)
Property, Plant and Equipment [Line Items]
Number of acres, Gross | a	1,127
Number of acres, Net | a	345
Proceeds from sale of asset		$ 19,300,000			$ 20,803,912
Gain on sale of asset		$ 10,200,000
Working interest in new wells	20.00%
Percentage of payment on drilling and completion costs	24.375%
Number of acres disposed off, Gross | a		1,000
Number of acres disposed off, Net | a		403
Impairment charge on wells				$ 2,372,281
Income from well				22,159,498	29,366,595
Immaterial adjustment of suspended exploratory well costs			$ 449,541
Spade 17 #1 Exploratory Well [Member]
Property, Plant and Equipment [Line Items]
Impairment charge on wells				1,682,794
Cumulative income from well				472,000
Income from well					$ 82,000
Vertical Midland Basin Wells [Member]
Property, Plant and Equipment [Line Items]
Percentage of interest in asset disposed during period	10.625%
Number of gas and oil wells, Gross | Wells	5
Number of wells, Net | Wells	1.53
Number of gas and oil wells disposed off, Gross | Wells		12
Number of gas and oil wells disposed off, Net | Wells		4.7
Land [Member]
Property, Plant and Equipment [Line Items]
Proceeds from sale of asset	$ 1,230,000
Gain on sale of asset	$ 305,000
Mitchell Ranch [Member]
Property, Plant and Equipment [Line Items]
Impairment charge on wells				$ 1,814,441
Paradox Basin [Member]
Property, Plant and Equipment [Line Items]
Proceeds from sale of asset		$ 307,000
Gain on sale of asset		$ 288,000
Number of acres disposed off, Net | a		8,400

Property, Plant and Equipment43

Property, Plant and Equipment - Summary of Capitalization of Exploratory Well Costs (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Capitalized Exploratory Well Costs [Line Items]
Beginning balance	$ 4,186,061	$ 4,030,489
Additions pending the determination of proved reserves	8,131,204	174,389
Dispositions		(18,817)
Reclassification to proved	(2,165,155)
Impairments	(2,236,982)
Ending balance	7,888,128	4,186,061
Paradox Basin [Member]
Capitalized Exploratory Well Costs [Line Items]
Beginning balance	449,541	445,706
Additions pending the determination of proved reserves		22,652
Dispositions		(18,817)
Impairments	(449,541)
Ending balance		449,541
Mitchell Ranch [Member]
Capitalized Exploratory Well Costs [Line Items]
Beginning balance	3,736,520	3,584,783
Additions pending the determination of proved reserves	5,690,251	151,737
Impairments	(1,814,441)
Ending balance	7,612,330	$ 3,736,520
Wolfberry [Member]
Capitalized Exploratory Well Costs [Line Items]
Additions pending the determination of proved reserves	2,440,953
Reclassification to proved	(2,165,155)
Ending balance	$ 275,798

Property, Plant and Equipment44

Property, Plant and Equipment - Summary of Aging Analysis of Exploratory Costs (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Aging Of Capitalized Exploratory Well Costs [Line Items]
Exploratory well costs	$ 7,888,128	$ 4,186,061	$ 4,030,489
Exploratory Well Costs Capitalized for a Period of One Year or Less [Member]
Aging Of Capitalized Exploratory Well Costs [Line Items]
Exploratory well costs capitalized for a period	5,966,049	174,389
Exploratory Well Costs Capitalized for a Period of One to Two Years [Member]
Aging Of Capitalized Exploratory Well Costs [Line Items]
Exploratory well costs capitalized for a period	174,389	224,079
Exploratory Well Costs Capitalized for a Period of Greater Than Three Years [Member]
Aging Of Capitalized Exploratory Well Costs [Line Items]
Exploratory well costs capitalized for a period	$ 1,747,690	$ 3,787,593

Trade and Other Payables - Summ

Trade and Other Payables - Summary of Trade and Other Payables (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Payables and Accruals [Abstract]
Accounts payable - trade	$ 1,526,796	$ 2,693,097
Accrued liabilities	120,050	278,080
Trade and other payables	$ 1,646,846	$ 2,971,177

Trade and Other Payables - Addi

Trade and Other Payables - Additional Information (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Payables and Accruals [Abstract]
Accounts payable due to one counterparty	$ 1,253,267	$ 2,486,438

Credit Facility - Additional In

Credit Facility - Additional Information (Detail)	12 Months Ended
	Jun. 30, 2015USD ($)
Line of Credit Facility [Line Items]
Revolving line of credit	$ 100,000,000
Borrowing base of credit facility	37,500,000
Credit facility drawn down	$ 29,750,000
Credit facility expiration period	Aug. 31, 2016
Minimum [Member]
Line of Credit Facility [Line Items]
Minimum interest rate	3.50%
Minimum [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Credit facility interest rate	3.00%
Minimum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Credit facility interest rate	2.00%
Maximum [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Credit facility interest rate	3.50%
Maximum [Member] | Prime Rate [Member]
Line of Credit Facility [Line Items]
Credit facility interest rate	2.50%

Asset Retirement Liabilities -

Asset Retirement Liabilities - Additional Information (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligations [Line Items]
Estimated cash flows weighted-average rate adjusted for inflation	2.00%
Undiscounted amount of the estimated cash flows	$ 4,189,000	$ 3,579,000
Weighted-average credit adjusted risk free rate	10.20%
Minimum [Member]
Asset Retirement Obligations [Line Items]
Estimated cash flows payment period	10 years
Maximum [Member]
Asset Retirement Obligations [Line Items]
Estimated cash flows payment period	35 years

Asset Retirement Liabilities 49

Asset Retirement Liabilities - Schedule of Changes in Asset Retirement Liabilities (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning balance	$ 240,208	$ 200,531
Liabilities incurred	22,771	34,627
Liabilities settled	(8,870)	(13,941)
Accretion	25,297	21,190
Revisions in estimated liabilities	(616)	(2,199)
Ending balance	$ 278,790	$ 240,208

Shareholders' Equity - Schedule

Shareholders' Equity - Schedule of Changes in Warrants Issued (Detail) - Warrants [Member] - CAD / shares	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Class of Warrant or Right [Line Items]
Number of warrants, beginning balance	7,512,000	27,415,760
Number of warrants, exercised		(18,770,391)
Number of warrants, expired	(7,512,000)	(1,133,369)
Number of warrants, ending balance		7,512,000
Weighted average exercise price, beginning balance	CAD 0.65	CAD 0.69
Weighted average exercise price, exercised		0.70
Weighted average exercise price, expired	CAD 0.65	0.70
Weighted average exercise price, ending balance		CAD 0.65

Shareholders' Equity - Computat

Shareholders' Equity - Computation of Diluted Earning Per Share (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Numerator:
Net (loss) income	$ (565,153)	$ 15,403,651
Denominator:
Weighted average number of common shares (basic)	130,045,582	123,798,574
Dilutive effect of share options		1,626,501
Dilutive effect of warrants		1,974,874
Weighted average number of common shares (diluted)	130,045,582	127,399,949
Diluted (loss) income per common share	$ 0	$ 0.12

Shareholders' Equity - Addition

Shareholders' Equity - Additional Information (Detail)	12 Months Ended
	Jun. 30, 2015CAD / sharesshares	Jun. 30, 2014USD ($)shares
Class of Warrant or Right [Line Items]
Share-based payments recognized | $		$ 55,683
Stock options exercised, weighted average share price | CAD / shares	CAD 0.92
Employee Stock Option [Member]
Class of Warrant or Right [Line Items]
Share-based payments recognized | $		$ 55,683
Maximum [Member]
Class of Warrant or Right [Line Items]
Percentage that may be reserved for issuance pursuant to the exercise of stock options	10.00%
Term of stock options granted	10 years
Warrants [Member]
Class of Warrant or Right [Line Items]
Share options that are not dilutive	0	0
Share Options [Member]
Class of Warrant or Right [Line Items]
Share options that are not dilutive	4,270,000	2,612,500

Shareholders' Equity - Schedu53

Shareholders' Equity - Schedule of Changes in Stock Option Issued (Detail) - CAD / shares	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options Outstanding, Weighted Average Exercise Price, and Additional Disclosures [Abstract]
Number of options, beginning balance	6,632,500	6,862,500
Number of options, exercised	(922,500)
Weighted average exercise price, exercised	CAD 0.31
Number of options, expired	(1,440,000)	(230,000)
Number of options, ending balance	4,270,000	6,632,500
Weighted average exercise price, beginning balance	CAD 0.61	CAD 0.61
Weighted average exercise price, expired	0.55	0.68
Weighted average exercise price, ending balance	CAD 0.69	CAD 0.61

Shareholders' Equity - Summary

Shareholders' Equity - Summary of Stock Options Outstanding and Exercisable (Detail)	12 Months Ended
	Jun. 30, 2015CAD / sharesshares
Schedule Of Stock Option Activity [Line Items]
Options outstanding, Number of options	4,270,000
Options outstanding, Weighted average remaining life (years)	1 year 3 months 22 days
Options exercisable, Number of options	4,270,000
Options exercisable, weighted average remaining life(years	1 year 3 months 22 days
Exercise Price Range $0.50 to $0.60 [Member]
Schedule Of Stock Option Activity [Line Items]
Exercise price, Lower Limit | CAD / shares	CAD 0.50
Exercise price, Upper Limit | CAD / shares	CAD 0.60
Options outstanding, Number of options	1,657,500
Options outstanding, Weighted average remaining life (years)	1 year 8 months 12 days
Options exercisable, Number of options	1,657,500
Options exercisable, weighted average remaining life(years	1 year 8 months 12 days
Exercise Price Range $0.80 [Member]
Schedule Of Stock Option Activity [Line Items]
Exercise price, Upper Limit | CAD / shares	CAD 0.80
Options outstanding, Number of options	2,612,500
Options outstanding, Weighted average remaining life (years)	1 year 22 days
Options exercisable, Number of options	2,612,500
Options exercisable, weighted average remaining life(years	1 year 22 days

Related Party Transactions - Su

Related Party Transactions - Summary of Fees and Expenses to Related Parties (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Related Party Transaction [Line Items]
Total	$ 83,620	$ 80,294
Law Firm [Member]
Related Party Transaction [Line Items]
Legal fees	42,013	38,972
Abajo Gas Transmission Company, LLC [Member]
Related Party Transaction [Line Items]
Transportation and marketing costs	$ 41,607	$ 41,322

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Related Party Transactions [Abstract]
Trade and other payables owing to related parties	$ 33,320	$ 47,104

Financial Instruments - Additio

Financial Instruments - Additional Information (Detail)	12 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2015CAD	Jun. 30, 2014USD ($)$ / bbl	Apr. 01, 2015Bbls$ / bbl
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Allowance for doubtful accounts	$ 0		$ 0
Accounts receivable owed from one counterparty	$ 1,532,382		2,991,585
Trade and other payables repayment period	90 days	90 days
Credit facility final maturity date	Aug. 31, 2016	Aug. 31, 2016
Interest rate, higher	1.00%
Derivative instrument interest rate higher, net loss and comprehensive loss	$ (136,000)
Interest rate, lower	1.00%
Derivative instrument interest rate lower, net loss and comprehensive loss	$ (115,000)
Depreciation or appreciation, foreign currency translation adjustment, percent	10.00%	10.00%
Increase or decrease in earnings or loss, due to depreciation or appreciation of currency	$ 858,919	CAD 858,919
Barrels of fuel covered under derivative contracts | Bbls				9,000
Strike price per barrel | $ / bbl				50
Unrealized loss on derivative financial instrument	(140,040)		$ (15,163)
Derivative floor price, price risk | $ / bbl			80
Derivative financial instruments loss	$ (140,040)		$ (63,633)
Eurodollar Loans [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Credit facility maximum expiration period	90 days	90 days
Floating Rate Loans [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Credit facility final maturity date	Aug. 29, 2016	Aug. 29, 2016
Crown Quest [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Allowance for doubtful accounts	$ 0		0
Accounts receivable owed from one counterparty	$ 1,532,385		$ 2,991,585
Minimum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative cap price, price risk | $ / bbl			104
Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative cap price, price risk | $ / bbl			105

Financial Instruments - Summary

Financial Instruments - Summary of Aging of Trade and Other Receivables (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Trade and other receivables
0 to 60 days	$ 1,592,126	$ 3,083,365
61 to 120 days	8,357	6,762
> 120 days	59,652	52,890
Total	$ 1,660,135	$ 3,143,017

Financial Instruments - Summa59

Financial Instruments - Summary of Expected Remaining Contractual Maturities for Financial Liabilities (Detail)	Jun. 30, 2015USD ($)
Contractual Obligation Fiscal Year Maturity [Line Items]
Total	$ 35,744,212
Less than 1 year	1,646,846
One to two years	29,908,366
More than two years	4,189,000
Asset Retirement Obligation [Member]
Contractual Obligation Fiscal Year Maturity [Line Items]
Total	4,189,000
More than two years	4,189,000
Trade and Other Payables [Member]
Contractual Obligation Fiscal Year Maturity [Line Items]
Total	1,646,846
Less than 1 year	1,646,846
Credit Facility [Member]
Contractual Obligation Fiscal Year Maturity [Line Items]
Total	29,908,366
One to two years	$ 29,908,366

Financial Instruments - Summa60

Financial Instruments - Summary of Expected Remaining Contractual Maturities for Financial Liabilities (Parenthetical) (Detail)	Jun. 30, 2015USD ($)
Credit Facility [Member]
Contractual Obligation Fiscal Year Maturity [Line Items]
Accrued Interest	$ 158,366

Financial Instruments - Summa61

Financial Instruments - Summary of Currency Risk (Detail) - 12 months ended Jun. 30, 2015	USD ($)	CAD
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items]
Net assets exposure		CAD 8,589,191
Effect of +/- 10% change in currency	$ 858,919	858,919
Cash [Member]
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items]
Cash		8,670,365
Trade and Other Payables [Member]
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items]
Trade and other payables		(89,370)
Trade Accounts Receivable [Member]
Financial Statement Line Items with Differences in Reported Amount and Reporting Currency Denominated Amounts [Line Items]
Cash		CAD 8,196

Financial Instruments - Summa62

Financial Instruments - Summary of Currency Risk (Parenthetical) (Detail)	12 Months Ended
	Jun. 30, 2015
Foreign Currency [Abstract]
Depreciation or appreciation, foreign currency translation adjustment, percent	10.00%

Supplemental Cash Flow Inform63

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Non-cash financing activities:
Fair value of stock options transferred to common shares on exercise of stock options	$ 205,260
Fair value of warrants transferred to common shares on exercise of warrants		$ 3,220,425
Additional cash flow information:
Interest paid	917,052	874,226
Taxes paid	$ 503,668	$ 783,972

Segmented Information - Additio

Segmented Information - Additional Information (Detail)	12 Months Ended
	Jun. 30, 2015SegmentGeographicalAreas
Segment Reporting [Abstract]
Number of operating segments | Segment	1
Number of geographic areas considered as reportable operating segments	2

Segmented Information - Schedul

Segmented Information - Schedule of Revenues and Capital Assets (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Segment Reporting Information [Line Items]
Revenue and other income	$ 22,152,726	$ 29,392,952
Property, plant and equipment	107,283,684	91,812,527
Interest Income [Member]
Segment Reporting Information [Line Items]
Revenue and other income	133,268	89,990
Petroleum [Member]
Segment Reporting Information [Line Items]
Revenue and other income	17,227,574	23,507,100
Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenue and other income	2,198,265	2,212,065
Natural Gas Liquids [Member]
Segment Reporting Information [Line Items]
Revenue and other income	2,593,619	3,583,797
Canada [Member]
Segment Reporting Information [Line Items]
Revenue and other income	133,268	89,990
Property, plant and equipment	951	1,021
Canada [Member] | Interest Income [Member]
Segment Reporting Information [Line Items]
Revenue and other income	133,268	89,990
USA [Member]
Segment Reporting Information [Line Items]
Revenue and other income	22,019,458	29,302,962
Property, plant and equipment	107,282,733	91,811,506
USA [Member] | Petroleum [Member]
Segment Reporting Information [Line Items]
Revenue and other income	17,227,574	23,507,100
USA [Member] | Natural Gas [Member]
Segment Reporting Information [Line Items]
Revenue and other income	2,198,265	2,212,065
USA [Member] | Natural Gas Liquids [Member]
Segment Reporting Information [Line Items]
Revenue and other income	$ 2,593,619	$ 3,583,797

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Income Tax Disclosure [Abstract]
Net (loss) income before income taxes	$ (83,789)	$ 24,818,436
Combined statutory tax rate	26.00%	26.00%
Income tax (recovery) expense computed at statutory tax rate	$ (21,785)	$ 6,452,793
Changes in valuation allowance	3,499	214,513
Change in estimate	9,893	356,201
Non-deductible (taxable) expenditures	378,822	584,411
Effect of different statutory tax rates on earnings in subsidiaries	110,935	2,082,510
Equity investment taxable loss pick-up		(275,643)
Income tax expense	481,364	9,414,785
Current income tax expense	(145,866)	860,050
Deferred income tax expense	627,230	8,554,735
Income tax expense	$ 481,364	$ 9,414,785

Income Taxes - Schedule of Sign

Income Taxes - Schedule of Significant Components of Deferred Tax Assets and Liabilities (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Deferred tax assets:
Asset retirement liabilities	$ 94,789	$ 81,671
Alternative minimum tax credits	272,830	272,830
Trade and other payables	47,614
Credit facility	207,688
Capital loss carry forwards		17,669
Share issuance costs	2,106	31,315
Excess tax value of intangibles over book value	397	463
Excess tax value of property, plant and equipment over book value	681	1,136
Exploration and evaluation assets	599,091	673,948
Non-capital losses carry forwards	12,334,869	10,149,816
Gross deferred tax assets	13,560,065	11,228,848
Valuation allowance	(2,851,490)	(2,847,991)
Net deferred tax assets	10,708,575	8,380,857
Deferred tax liabilities:
Credit facility		(264,683)
Unrealized mark-to-market gains	(2,974,446)	(1,006,795)
Property, plant and equipment	(25,231,821)	(22,012,190)
Gross deferred tax liabilities	(28,206,267)	(23,283,668)
Net deferred tax assets (liabilities)	$ (17,497,692)	$ (14,902,811)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Income Tax Disclosure [Abstract]
Income tax loss carry forwards, recognized	$ 29,663,690	$ 14,806,716
Recognized tax losses, expiration period	Between 2031 and 2035
Income tax loss carry forwards, unrecognized	$ 8,650,700	$ 7,289,792
Unrecognized tax losses, expiration period	Between 2026 and 2035

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - CAD / shares	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Subsequent Event [Line Items]
Number of stock options expired	1,440,000	230,000
Exercise price of stock options expired	CAD 0.55	CAD 0.68
Subsequent Event [Member]
Subsequent Event [Line Items]
Number of stock options expired	260,000
Exercise price of stock options expired	CAD 0.60

Supplemental Information on O70

Supplemental Information on Oil and Gas Exploration and Production Activities - Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Extractive Industries [Abstract]
Property acquisition costs, Proved	$ 71,059	$ 24,948
Property acquisition costs, Unproved	14,074	12,532
Property acquisition costs, Exploration costs	5,951,975	415,361
Property acquisition costs, Development costs	22,013,097	36,229,566
Total costs incurred	$ 28,050,205	$ 36,682,407

Supplemental Information on O71

Supplemental Information on Oil and Gas Exploration and Production Activities - Additional Information (Detail) Boe in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2013Boe	Jun. 30, 2015USD ($)WellsBoelb$ / bbl$ / MMBTU	Jun. 30, 2014WellsBoe$ / bbl$ / MMBTU	Jun. 30, 2013$ / bbl$ / MMBTU
Reserve Quantities [Line Items]
Impairments | $		$ 2,372,281
Discount to present value		10.00%	10.00%
Pressure base of natural gas pounds per square inch | lb		14.73
Natural gas computation description		Natural gas volumes are in thousands of cubic feet (Mcf) at a pressure base of 14.73 pounds per square inch and volumes for oil are in barrels (Bbls). Total volumes are presented in barrels of oil equivalent (BOE). For this computation, one barrel is equivalent to 6,000 cubic feet of natural gas.
Spade 17 #1 Exploratory Well [Member]
Reserve Quantities [Line Items]
Impairments | $		$ 1,682,794
Reserve Estimate [Member] | Oil [Member]
Reserve Quantities [Line Items]
Estimated reserve oil and gas prices | $ / bbl		71.68	100.27	91.60
Reserve Estimate [Member] | Natural Gas [Member]
Reserve Quantities [Line Items]
Estimated reserve oil and gas prices | $ / MMBTU		3.361	4.104	3.459
Mitchell Ranch [Member]
Reserve Quantities [Line Items]
Impairments | $		$ 1,814,441
Wolfberry [Member]
Reserve Quantities [Line Items]
Proved reserve, extensions and discoveries		6,047	1,349
Proved reserve, production		505	442
Proved reserve, revisions of prior estimates		336	1,890
Proved reserve, sale	1,217
Proved undeveloped reserve, sale	554
Wolfberry [Member] | Minimum [Member]
Reserve Quantities [Line Items]
Number of producing wells, gross | Wells		91	67
Number of producing wells, net | Wells		37.18	27.93
Wolfberry [Member] | Maximum [Member]
Reserve Quantities [Line Items]
Number of producing wells, gross | Wells		109	91
Number of producing wells, net | Wells		44.69	37.18

Supplemental Information on O72

Supplemental Information on Oil and Gas Exploration and Production Activities - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Future net cash flows	$ 4,189,000	$ 3,579,000
Discounted future net cash flows	69,970,659	82,475,908	$ 55,563,510
Proved Reserves [Member]
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows [Line Items]
Future cash flows	581,163,900	488,770,334
Future production costs	(179,031,200)	(133,828,860)
Future development costs	(128,842,600)	(64,661,351)
Future income taxes	(76,612,819)	(86,035,972)
Future net cash flows	196,677,281	204,244,151
Annual discount at 10% for estimated timing of cash flows	(126,706,622)	(121,768,244)
Discounted future net cash flows	$ 69,970,659	$ 82,475,908

Supplemental Information on O73

Supplemental Information on Oil and Gas Exploration and Production Activities - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Extractive Industries [Abstract]
Discount to present value	10.00%	10.00%

Supplemental Information on O74

Supplemental Information on Oil and Gas Exploration and Production Activities - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Extractive Industries [Abstract]
Balance, beginning of year	$ 82,475,908	$ 55,563,510
Changes resulting from:
Sales of oil and gas produced, net of production costs	(15,889,756)	(24,416,663)
Sales of reserves in place		(16,911,630)
Discoveries and extensions	23,979,600	19,984,162
Changes in prices and production costs	(42,421,155)	21,170,364
Changes in estimated future development costs	(8,827,304)	(26,847,805)
Development costs incurred during the period	21,809,476	36,229,566
Revisions of previous quantity estimates	(1,557,183)	15,765,294
Net change in income taxes	6,289,739	(13,484,610)
Accretion of discount	11,169,119	7,129,418
Changes in production rates and other	(7,057,785)	8,294,302
Net change	(12,505,249)	26,912,398
Balance, end of year	$ 69,970,659	$ 82,475,908

Supplemental Information on O75

Supplemental Information on Oil and Gas Exploration and Production Activities - Summary of Net Proved and Proved Developed Reserve (Detail)	12 Months Ended
	Jun. 30, 2015BoebblMcf	Jun. 30, 2014BoebblMcf	Jun. 30, 2013BoebblMcf
Oil [Member]
Reserve Quantities [Line Items]
Net proved reserves, Beginning balance	3,950,079	3,653,262
Discoveries and extensions	3,086,400	1,023,690
Revisions of prior estimates	(132,914)	327,408
Sales of reserves in place		(808,114)
Production	(274,185)	(246,167)
Net proved reserves, Ending balance	6,629,380	3,950,079
Net Proved Developed Reserves	2,226,910	2,102,913	1,805,485
Net Proved Undeveloped Reserves	4,402,470	1,847,166	1,847,777
Natural Gas [Member]
Reserve Quantities [Line Items]
Net proved reserves, Beginning balance | Mcf	21,287,605	13,589,316
Discoveries and extensions | Mcf	8,595,200	1,950,095
Revisions of prior estimates | Mcf	1,927,264	9,377,971
Sales of reserves in place | Mcf		(2,451,430)
Production | Mcf	(670,309)	(1,178,347)
Net proved reserves, Ending balance | Mcf	19,571,280	21,287,605
Net Proved Developed Reserves | Mcf	6,723,130	11,564,489	6,585,058
Net Proved Undeveloped Reserves | Mcf	12,848,150	9,723,116	7,004,258
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Net proved reserves, Beginning balance	1,928,080
Discoveries and extensions	1,528,700
Revisions of prior estimates	147,833
Production	(119,513)
Net proved reserves, Ending balance	3,485,100	1,928,080
Net Proved Developed Reserves	1,200,620	1,047,356
Net Proved Undeveloped Reserves	2,284,480	880,724
BOE [Member]
Reserve Quantities [Line Items]
Net proved reserves, Beginning balance | Boe	7,498,013	5,918,148
Discoveries and extensions | Boe	6,047,633	1,348,706
Revisions of prior estimates | Boe	336,130	1,890,403
Sales of reserves in place | Boe		(1,216,686)
Production | Boe	(505,416)	(442,558)
Net proved reserves, Ending balance | Boe	13,376,360	7,498,013
Net Proved Developed Reserves | Boe	4,548,052	4,030,328	2,902,995
Net Proved Undeveloped Reserves | Boe	8,828,308	3,467,685	3,015,153
Net Proved Developed Reserves | Boe	4,548,052	4,030,328	2,902,995
Net Proved Undeveloped Reserves | Boe	8,828,308	3,467,685	3,015,153

Uncategorized Items - lvl-20150

Label	Element	Value
Short-term Investments	us-gaap_ShortTermInvestments	$ 11,327,513
Short-term Investments	us-gaap_ShortTermInvestments	8,628,623
Cash	us-gaap_Cash	2,628,377
Cash	us-gaap_Cash	$ 119,385