Evolution Petroleum (EPM) 10-K 9 Sep 16 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Jun. 30, 2016	Sep. 07, 2016	Dec. 31, 2015
Document and Entity Information
Entity Registrant Name	EVOLUTION PETROLEUM CORP
Entity Central Index Key	1,006,655
Current Fiscal Year End Date	--06-30
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		32,905,982
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 116,929,484

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Current assets
Cash and cash equivalents	$ 34,077,060	$ 20,118,757
Receivables	2,638,188	3,122,473
Deferred tax asset	105,321	82,414
Derivative assets, net	14,132	0
Prepaid expenses and other current assets	251,749	369,404
Total current assets	37,086,450	23,693,048
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization	59,970,463	45,186,886
Other property and equipment, net	28,649	276,756
Total property and equipment, net	59,999,112	45,463,642
Other assets	365,489	726,037
Total assets	97,451,051	69,882,727
Current liabilities
Accounts payable	5,809,107	8,173,878
Accrued liabilities and other	2,097,951	855,373
Derivative liabilities, net	0	109,974
State and federal taxes payable	621,850	190,032
Total current liabilities	8,528,908	9,329,257
Long term liabilities
Deferred income taxes	11,840,693	11,242,551
Asset retirement obligations	760,300	715,767
Deferred rent	0	18,575
Total liabilities	21,129,901	21,306,150
Commitments and contingencies (Note 18)
Stockholders' equity
Preferred stock, par value $0.001; 5,000,000 shares authorized: 8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at June 30, 2016 and 2015, respectively, with a total liquidation preference of $7,932,975 ($25.00 per share)	317	317
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,907,863 and 32,845,205 shares as of June 30, 2016 and 2015, respectively	32,907	32,845
Additional paid-in capital	47,171,563	36,847,289
Retained earnings	29,116,363	11,696,126
Total stockholders' equity	76,321,150	48,576,577
Total liabilities and stockholders' equity	$ 97,451,051	$ 69,882,727

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, issued shares	32,907,863	32,845,205
Common stock, outstanding shares	32,907,863	32,845,205
Series A Cumulative Preferred Stock
Preferred stock, shares authorized	1,000,000	1,000,000
Cumulative Preferred Stock (as a percent)	8.50%	8.50%
Preferred stock, shares issued	317,319	317,319
Preferred stock, shares outstanding	317,319	317,319
Preferred stock, total liquidation preference (in dollars)	$ 7,932,975	$ 7,932,975
Preferred stock, liquidation preference (in dollars per share)	$ 25	$ 25

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Revenues
Total revenues		$ 26,349,502	$ 27,841,265	$ 17,673,508
Operating costs
Production costs		9,062,179	9,335,244	1,193,573
Depreciation, depletion and amortization		5,165,120	3,615,737	1,228,685
Accretion of discount on asset retirement obligations		49,054	34,866	41,626
General and administrative expenses	[1]	9,079,597	6,256,783	8,388,291
Restructuring charges		1,257,433	(5,431)	1,293,186
Total operating costs		24,684,315	19,257,568	12,145,361
Income from operations		1,665,187	8,583,697	5,528,147
Other
Gain on settled derivative instruments, net		3,315,123	0	0
Gain (loss) on unsettled derivative instruments, net		124,106	(109,974)	0
Delhi field litigation settlement		28,096,500	0	0
Delhi field insurance recovery related to pre-reversion event		1,074,957	0	0
Interest and other income		26,211	35,991	30,256
Interest (expense)		(70,943)	(73,636)	(69,092)
Income before income tax provision		34,231,141	8,436,078	5,489,311
Income tax provision		9,570,779	3,444,221	1,891,998
Net income attributable to the Company		24,660,362	4,991,857	3,597,313
Dividends on preferred stock		674,302	674,302	674,302
Net income attributable to common shareholders		$ 23,986,060	$ 4,317,555	$ 2,923,011
Earnings per common share
Basic (in dollars per share)		$ 0.73	$ 0.13	$ 0.09
Diluted (in dollars per share)		$ 0.73	$ 0.13	$ 0.09
Weighted average number of common shares outstanding
Basic (in shares)		32,810,375	32,817,456	30,895,832
Diluted (in shares)		32,861,231	32,924,018	32,564,067
Crude Oil
Revenues
Total revenues		$ 26,130,762	$ 27,761,291	$ 17,460,392
Natural Gas Liquids
Revenues
Total revenues		7,885	37,227	117,166
Natural Gas
Revenues
Total revenues		2,895	26,601	95,950
Artificial Lift Technology
Revenues
Total revenues		207,960	16,146	0
Operating costs
Production costs		$ 70,932	$ 20,369	$ 0
[1]	General and administrative expenses for the years ended June 30, 2016, 2015 and 2014 included non-cash stock-based compensation expense of $1,750,209, $943,653, and $1,352,322, respectively. These years also included litigation expenses of $2,729,755, $1,015,105, and $300,564, respectively.

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Non-cash stock-based compensation expense	$ 1,750,209	$ 943,653	$ 1,352,322
General and Administrative Expense
Non-cash stock-based compensation expense	1,750,209	943,653	1,352,322
Litigation expense	$ 2,729,755	$ 1,015,105	$ 300,564

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Cash Flows From Operating Activities
Net income attributable to the Company	$ 24,660,362	$ 4,991,857	$ 3,597,313
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	5,211,494	3,664,373	1,272,778
Impairments included in restructuring charge	569,228	0	0
Stock-based compensation	1,750,209	943,653	1,352,322
Stock-based compensation related to restructuring	59,339	0	376,365
Accretion of discount on asset retirement obligations	49,054	34,866	41,626
Settlement of asset retirement obligations	0	(223,564)	(315,952)
Deferred income taxes	575,235	1,422,489	1,344,812
Deferred rent	0	(17,145)	(17,145)
(Gain) loss on derivative instruments, net	(3,439,229)	109,974	0
Noncash (gain) on Delhi field litigation settlement	(596,500)	0	0
Write-off of deferred loan costs	50,414	0	0
Changes in operating assets and liabilities:
Receivables	484,285	(1,665,261)	507,592
Prepaid expenses and other current assets	24,754	378,049	(480,899)
Accounts payable and accrued expenses	822,730	551,452	663,645
Income taxes payable	431,818	190,032	(233,548)
Net cash provided by operating activities	30,653,193	10,380,775	8,108,909
Cash flows from investing activities
Derivative settlements received	3,633,831	0	0
Proceeds from asset sales	0	398,242	542,347
Development of oil and natural gas properties	(21,095,901)	(4,890,909)	(966,931)
Acquisitions of oil and natural gas properties	0	0	(59,315)
Capital expenditures for technology and other equipment	(6,883)	(313,059)	(312,890)
Maturities of certificates of deposit	0	0	250,000
Other assets	(161,345)	(236,559)	(202,017)
Net cash used by investing activities	(17,630,298)	(5,042,285)	(748,806)
Cash flows from financing activities
Proceeds from the exercise of stock options	51,000	141,600	3,252,801
Acquisitions of treasury stock	(1,357,185)	(333,841)	(1,655,251)
Common stock dividends paid	(6,565,823)	(9,833,642)	(9,723,833)
Preferred stock dividends paid	(674,302)	(674,302)	(674,302)
Deferred loan costs	(168,972)	(94,075)	(63,535)
Tax benefits related to stock-based compensation	9,650,657	1,633,946	509,096
Other	33	67	6,850
Net cash provided (used) by financing activities	935,408	(9,160,247)	(8,348,174)
Net increase (decrease) in cash and cash equivalents	13,958,303	(3,821,757)	(988,071)
Cash and cash equivalents, beginning of year	20,118,757	23,940,514	24,928,585
Cash and cash equivalents, end of year	$ 34,077,060	$ 20,118,757	$ 23,940,514

Consolidated Statement of Chang

Consolidated Statement of Changes in Stockholders' Equity - USD ($)	Total	Preferred	Common Stock	Additional Paid-in Capital	Retained Earnings	Treasury Stock
Balance at Jun. 30, 2013	$ 54,836,161	$ 317	$ 29,410	$ 31,813,239	$ 24,013,035	$ (1,019,840)
Balance (in shares) at Jun. 30, 2013		317,319	28,608,969
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock			$ 40	(40)
Issuance of restricted common stock (shares)			39,732
Exercise of warrants			$ 905	(905)
Exercise of warrants (in shares)			905,391
Exercise of stock options	3,871,407		$ 3,299	3,868,108
Exercise of stock options (shares)			3,299,367
Forfeiture of restricted stock			$ (51)	51
Forfeiture of restricted stock (in shares)			(51,099)
Acquisition of treasury stock	$ (2,273,857)					(2,273,857)
Acquisitions of treasury stock (shares)	(186,714)		(186,714)
Retirements of treasury stock			$ (988)	(3,292,709)		3,293,697
Stock-based compensation	$ 1,728,687			1,728,687
Tax benefits related to stock-based compensation	509,096			509,096
Net income	3,597,313				3,597,313
Common stock cash dividends	(9,723,833)				(9,723,833)
Preferred stock cash dividends	(674,302)				(674,302)
Recovery of short swing profits	6,850			6,850
Balance at Jun. 30, 2014	51,877,522	$ 317	$ 32,615	34,632,377	17,212,213	0
Balance (in shares) at Jun. 30, 2014		317,319	32,615,646
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock	67		$ 214	(147)
Issuance of restricted common stock (shares)			213,466
Exercise of stock options	$ 141,600		$ 87	141,513
Exercise of stock options (shares)	87,000		87,000
Acquisition of treasury stock	$ (504,124)					(504,124)
Acquisitions of treasury stock (shares)			(70,907)
Retirements of treasury stock			$ (71)	(504,053)		504,124
Stock-based compensation	943,653			943,653
Tax benefits related to stock-based compensation	1,633,946			1,633,946
Net income	4,991,857				4,991,857
Common stock cash dividends	(9,833,642)				(9,833,642)
Preferred stock cash dividends	(674,302)				(674,302)
Balance at Jun. 30, 2015	48,576,577	$ 317	$ 32,845	36,847,289	11,696,126	0
Balance (in shares) at Jun. 30, 2015		317,319	32,845,205
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock	33		$ 272	(239)
Issuance of restricted common stock (shares)			272,098
Exercise of stock options	$ 127,500		$ 50	127,450
Exercise of stock options (shares)	50,000		50,000
Forfeiture of restricted stock			$ (41)	41
Forfeiture of restricted stock (in shares)			(40,758)
Acquisition of treasury stock	$ (1,263,402)					(1,263,402)
Acquisitions of treasury stock (shares)			(218,682)
Retirements of treasury stock			$ (219)	(1,263,183)		1,263,402
Stock-based compensation	1,809,548			1,809,548
Tax benefits related to stock-based compensation	9,650,657			9,650,657
Net income	24,660,362				24,660,362
Common stock cash dividends	(6,565,823)				(6,565,823)
Preferred stock cash dividends	(674,302)				(674,302)
Balance at Jun. 30, 2016	$ 76,321,150	$ 317	$ 32,907	$ 47,171,563	$ 29,116,363	$ 0
Balance (in shares) at Jun. 30, 2016		317,319	32,907,863

Organization and Basis of Prepa

Organization and Basis of Preparation	12 Months Ended
	Jun. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Preparation	Organization and Basis of Preparation Nature of Operations. Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of oil and gas reserves within known oil and gas resources utilizing conventional and proprietary technology. Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. As a result of the separation of our GARP ® artificial lift technology operations discussed in Note 8, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified as appropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues included crude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells that utilized the technology, together with service revenues derived from the use of the Company’s technology in third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oil and gas production costs and cost of artificial lift technology services. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents. Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of joint interest owner obligations due within 30 days of the invoice date, accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2016 and 2015 , no allowance for doubtful accounts was considered necessary. Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized. Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent , and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 -month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Tests did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2016 , 2015 or 2014 . Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furniture and equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years . The assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred. Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense. Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricing model to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fair value is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that the recipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service. Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment. Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues. Derivative Instruments. The Company uses derivative transactions to reduce its exposure to oil price volatility. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to a ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as a result of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes. Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computer equipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment. Intangible Assets - Intellectual Property. The Company has capitalized the external costs, consisting primarily of legal costs, related to securing its patents and trademarks. The costs related to patents were amortized over the remaining patent life which was less than the expected useful life of each patent. Trademarks have a perpetual life and were not amortized. Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense. Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common shares outstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants, and contingent restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method. Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shall be assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPS computation. Potentially dilutive common shares are excluded from the computation if their effect is anti-dilutive. Recent Accounting Pronouncements. In August 2015, the FASB issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 would have been effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provided for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements, if any. In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” as part of their simplification initiatives. The standard requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The update is effective for public company annual reporting periods beginning after December 15, 2016, and may be adopted prospectively or retrospectively with early adoption permitted. The Company plans to early adopt this standard the first quarter of year ended June 30, 2017 and does not believe that adoption of this update will have a material impact on our results of operations, financial position or cash flows. On February 25, 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than 12 months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our condensed consolidated financial statements. On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company plans to early adopt this standard during the first quarter of the year ended June 30, 2017. The adoption of this standard will result in all excess tax benefits or deficiencies being recognized as tax expense or benefit in the reporting period they occur regardless of whether the benefit reduces taxes payable in the current period. On the statement of cash flows excess tax benefits or deficiencies will be classified along with other income tax as an operating activity and cash paid by the Company when directly withholding shares for tax withholding purposes will continue to be classified as a financing activity. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements, but does not expect the impact of adoption to be material.

Dehli Field Litigation Settleme

Dehli Field Litigation Settlement	12 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Dehli Field Litigation Settlement	Delhi Field Litigation Settlement On June 24, 2016, Evolution Petroleum Corporation, together with its subsidiaries NGS Sub Corp. and Tertiaire Resources Company (collectively, “Evolution”), entered into a settlement agreement with Denbury Resources, Inc. and Denbury Onshore, LLC, a subsidiary of Denbury Resources Inc. (together with Denbury Onshore, "Denbury"), to resolve all outstanding disputes and claims between the parties, including claims related to the litigation between Evolution and Denbury with respect to the Delhi field in northeastern Louisiana. The Delhi field litigation between the parties has been dismissed by the Court with prejudice. In connection with this settlement, the Company recognized a $28.1 million settlement gain consisting of a $27.5 million cash payment made by Denbury together with its conveyance to Evolution of a 23.9% working interest in the Mengel Sand Interval, a separate interval within the boundaries of the Delhi field which is not currently producing and for which we estimated a Level 2 fair value of $596,500 . In addition, effective July 1, 2016, Denbury will be credited with an additional 0.2226% overriding royalty interest in the Delhi field to remedy a previous dispute regarding the interests conveyed in the original transaction between the parties. See Note 18 — Commitments and Contingencies.

Receivables

Receivables	12 Months Ended
	Jun. 30, 2016
Receivables [Abstract]
Receivables	Receivables As of June 30, 2016 and June 30, 2015 our receivables consisted of the following: June 30, June 30, Receivables from oil and gas sales $ 2,637,593 $ 3,122,155 Other 595 318 Total receivables $ 2,638,188 $ 3,122,473

Prepaid Expenses and Other Curr

Prepaid Expenses and Other Current Assets	12 Months Ended
	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid Expenses and Other Current Assets	Prepaid Expenses and Other Current Assets As of June 30, 2016 and June 30, 2015 our prepaid expenses and other current assets consisted of the following: June 30, June 30, Prepaid insurance $ 168,681 $ 178,994 Prepaid federal and state income taxes — 22,542 Equipment inventory (a) — 81,538 Retainers and deposits 30,568 26,978 Other prepaid expenses 52,500 59,352 Prepaid expenses and other current assets $ 251,749 $ 369,404 (a) As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged to restructuring costs as part of the separation of our artificial lift technology operations.

Property and Equipment

Property and Equipment	12 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment [Abstract]
Property and Equipment	Property and Equipment As of June 30, 2016 and June 30, 2015 , our oil and natural gas properties and other property and equipment consisted of the following: June 30, June 30, Oil and natural gas properties: Property costs subject to amortization $ 77,408,353 $ 57,718,653 Less: Accumulated depreciation, depletion, and amortization (17,437,890 ) (12,531,767 ) Unproved properties not subject to amortization — — Oil and natural gas properties, net 59,970,463 45,186,886 Other property and equipment: Furniture, fixtures and office equipment, at cost 228,752 287,680 Artificial lift technology equipment, at cost 7,000 319,994 Less: Accumulated depreciation (207,103 ) (330,918 ) Other property and equipment, net $ 28,649 $ 276,756 As of June 30, 2016 and 2015 , all oil and gas property costs were being amortized. During the year ended June 30, 2016 , the Company incurred capital expenditures of $19.0 million for the Delhi field, including approximately $16.4 million for the NGL plant project which is currently under construction. We have incurred $21.5 million on a cumulative basis for the NGL plant out of a total authorized commitment of $24.6 million , with a remaining balance of approximately $3.1 million . As described in Note 3 – Delhi Field Litigation Settlement, we received a 23.9% working interest in the Mengel Interval (currently non-producing) having an estimated fair value of $596,500 . On December 31, 2015, as described in Note 8 — Restructuring, we transferred our residual artificial lift technology equipment to new entity not controlled by the Company. We recorded a charge of $210,392 to expense most of the remaining capitalized costs of artificial lift equipment installed in the wells of a third-party customer. Under our installation contracts, we had funded the majority of the incremental equipment and installation costs in exchange for 25% of the net profits from production, as defined, for as long as the technology remains in the wells. During the year ended ended June 30, 2015, we incurred $217,733 of costs related to installing our artificial lift technology on third party wells and recorded an impairment charge of $275,682 reflecting the unrecovered installation costs, net of estimated salvage value. During the year ended June 30, 2014, we incurred $377,943 of installation costs. Impairment charges are included in depreciation, depletion and amortization expense on the consolidated statement of operations. On October 24, 2014, we sold all of our remaining mineral interest and assets in the Mississippi Lime project for proceeds of $389,165 and the buyer's assumption of all abandonment liabilities. On December 1, 2013, we sold our producing assets and undeveloped reserves in the Lopez Field in South Texas in return for proceeds of $402,500 and the buyer's assumption of all abandonment liabilities. The net proceeds from these sales of our properties, including the reduction of asset retirement obligations, were recognized as a reduction of the cost of oil and gas properties.

Other Assets

Other Assets	12 Months Ended
	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Other Assets	Other Assets As of June 30, 2016 and June 30, 2015 our other assets consisted of the following: June 30, June 30, Royalty rights 108,512 — Less: Accumulated amortization of royalty rights (6,782 ) — Investment in Well Lift Inc., at cost 108,750 — Deferred loan costs 168,972 337,078 Less: Accumulated amortization of deferred loan costs (13,963 ) (147,057 ) Trademarks — 44,803 Patent costs — 538,276 Less: Accumulated amortization of patent costs — (47,063 ) Other assets, net $ 365,489 $ 726,037 During the year ended June 30, 2016 , our previous negotiations to obtain a new expanded secured credit facility were curtailed due to market conditions. As a result, the Company determined that $50,414 of deferred legal fees related to the proposed facility were unlikely to be utilized and were charged to expense. In addition, $107,196 of deferred costs incurred for title work in the Delhi field was charged to capitalized costs of oil and gas properties. Our existing unsecured credit facility expired in April 2016 and its associated deferred loan costs of $179,468 had been completely amortized. Contemporaneous with that facility's expiration, we entered into a secured credit facility provided by another financial institution, incurring $168,972 of deferred loan costs. Total amortization of costs related to our credit facilities for the year ended June 30, 2016 was $46,374 . See Note 8 – Restructuring for discussion of transactions associated with the separation of our artificial lift technology operations. The company accounts for its investment in Well Lift Inc. ("WLI") using the cost method under which any return of capital reduces cost and any dividends paid are recorded as income. This investment is considered a level 3 fair value measurement and its value will be evaluated for impairment periodically and when management identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment.

Restructuring

Restructuring	12 Months Ended
	Jun. 30, 2016
Restructuring and Related Activities [Abstract]
Restructuring	Restructuring Separation of GARP ® Artificial Lift Technology Operations During the quarter ended December 31, 2015, we conducted a strategic review of our GARP ® artificial lift technology operations and consummated a plan to separate and transfer these operations to a new entity controlled by the inventor of the technology, our former Senior Vice President of Operations, and certain former employees of the Company. We invested $108,750 in common and preferred stock of the new entity, WLI. We own 17.5% of WLI and our former employees that previously had primary responsibility for our GARP ® operations own the balance of the common stock. Our preferred stock is convertible at our option into common stock which would result in our ownership of 42.5% of WLI, based on the current capital structure of WLI. The company has no contractual exposure to losses of WLI, nor does it have any obligation or agreement to provide additional funding or support to WLI if it is needed. In connection with this transaction, three employees of the Company were terminated. We accrued a restructuring charge based on agreements with the employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for release from liabilities and other provisions including agreements not to compete. At December 31, 2015, we recorded a personnel restructuring charge of $688,205 consisting of $59,339 in stock-based compensation and $628,866 of accrued separation and benefits expense. Our current estimate of remaining restructuring obligations as of June 30, 2016 is as follows: Type of Cost December 31, Payments Adjustments to Cost June 30, Salary expense $ 530,387 $ (176,796 ) $ — $ 353,591 Payroll taxes and benefits expense 98,479 (32,582 ) — 65,897 Accrued liability for restructuring costs $ 628,866 $ (209,378 ) $ — $ 419,488 Other Restructuring Impairments Also in connection with the December 2015 separation of GARP ® , we and WLI entered into an agreement under which we transferred our technology assets, including our patents and trademarks, to WLI in exchange for a perpetual royalty of 5% on all future gross revenues associated with the GARP ® technology. We reduced the carrying value of these exchanged technology assets to our estimate of their expected discounted net present value, which was $108,512 . This estimate was based on the recent financial results from our artificial lift technology operations and the current depressed state of the oil and gas industry and the potential upside cases were assigned relatively low probabilities for accounting purposes. This resulted in an impairment charge of $469,395 . In addition, we transferred certain inventory and minor fixed assets to WLI which had no further use in our operations and were deemed to have negligible market or salvage value. This resulted in impairments of $92,901 to equipment inventory and $6,932 to fixed assets, respectively. These impairments total $569,228 and are included in restructuring charges. Restructuring of Oil and Gas Operations On November 1, 2013, we undertook an initiative to refocus our business that resulted in an adjustment of our workforce with less emphasis on engineering and greater emphasis on sales and marketing. In exchange for severance and non-compete agreements with the terminated employees, we recorded a restructuring charge of $1,332,186 representing $376,365 of stock-based compensation from the accelerated vesting of equity awards and $955,821 of estimated severance compensation and benefits to be paid during the twelve months ended December 31, 2014. All of the Company's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing the liability. Our disposition of the accrued restructuring charges is reflected in the following schedule: Type of Cost Balance at December 31, Payments Adjustment to Cost June 30, Salary expense $ 615,721 $ (615,721 ) $ — $ — Incentive compensation costs 185,525 (185,525 ) — — Payroll taxes and benefits expense 154,575 (110,144 ) (44,431 ) — Accrued liability for restructuring costs $ 955,821 $ (911,390 ) $ (44,431 ) $ —

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Jun. 30, 2016
Other Liabilities Disclosure [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other As of June 30, 2016 and June 30, 2015 our other current liabilities consisted of the following: June 30, June 30, Accrued incentive and other compensation $ 999,172 $ 578,910 Accrued restructuring charges 419,488 — Asset retirement obligations due within one year 201,896 57,223 Accrued royalties, including suspended accounts 49,580 75,164 Accrued franchise taxes 62,834 94,885 Payable for settled derivatives 318,708 — Accrued - other 46,273 49,191 Accrued liabilities and other $ 2,097,951 $ 855,373

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the years ended June 30, 2016 and 2015 : Years Ended 2016 2015 Asset retirement obligations—beginning of period $ 772,990 $ 352,215 Liabilities incurred (a) 28,505 564,019 Liabilities settled — (137,604 ) Liabilities sold — (52,526 ) Accretion of discount 49,054 34,866 Revisions to previous estimates 111,647 12,020 Asset retirement obligations — end of period 962,196 772,990 Less: current asset retirement obligations (201,896 ) (57,223 ) Long-term portion of asset retirement obligations $ 760,300 $ 715,767 (a) Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Stockholders' Equity	Stockholders' Equity Common Stock Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. We paid cash dividends of $6,565,823 , $9,833,642 and $9,723,833 from retained earnings to our common shareholders during the years ended June 30, 2016 , 2015 and 2014 , respectively. On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Since commencement in June 2015, we have repurchased 265,762 shares at an average price of $6.05 per share, for total cost of $1,609,008 . This includes 202,390 shares purchased during the year ended June 30, 2016, at an average price of $5.80 , for total cost of $1,173,899 . Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time. We have not repurchased any shares since December 2015. During the year ended June 30, 2014, we issued (i) 1,568,832 shares of our common stock upon the exercise of incentive stock options (ISOs), receiving cash proceeds totaling $3,252,801 , and (ii) 2,635,696 of our common shares upon cashless exercises of nonqualified stock options ("NQSOs") and incentive warrants, all being exercised on a net basis, except for 50,956 of previously acquired shares owned by option holders that were swapped in payment of the exercise price. The weighted average cost of these swapped shares was $12.14 . In fiscal 2014, we retired 801,889 shares of treasury stock acquired in previous fiscal years at a cost of $1,019,840 and 186,714 treasury shares acquired during fiscal 2014 from employees and directors at an average cost of $12.18 per share or $2,273,857 . The shares acquired in 2014 were received in satisfaction of payroll tax liabilities from the exercise of stock options and vesting of restricted stock (requiring cash outlays by us) and 50,956 shares were received from option holders in cashless stock option exercises, using stock previously owned by the option holder. Series A Cumulative Perpetual Preferred Stock At June 30, 2016 , there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding. The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to the holders thereof. Effective July 1, 2014, we can redeem this preferred stock at any time for the stated liquidation value of $25.00 per share plus accrued dividends. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, but subordinate to any of our existing and future debt. Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors through its Dividend Committee. We paid dividends of $674,302 to holders of our Series A Preferred Stock during each of the years ended June 30, 2016 , 2015 , and 2014 . Tax Treatment of Dividends to Recipients Based on our current projections for the fiscal year ending June 30, 2016 , we expect all preferred and common dividends for this fiscal year will be treated for tax purposes as qualified dividend income to the recipients. For the fiscal year ended June 30, 2015 , 100% of cash dividends on preferred stock were treated as qualified dividend income. For the same period, approximately 86% of cash dividends on common shares were treated as a return of capital to stockholders and the remainder of 14% were treated as qualified dividend income. For fiscal year ended June 30, 2014 , all cash dividends on preferred and common stock were treated for tax purposes as a return of capital to our shareholders.

Stock-Based Incentive Plan

Stock-Based Incentive Plan	12 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Incentive Plan	Stock-Based Incentive Plan Under the terms of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"), we have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company. The Plan authorizes the issuance of 6,500,000 shares of common stock prior to its expiration on October 24, 2017 and 282,133 shares remain available for grant as of June 30, 2016 . Stock Options and Incentive Warrants No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. No Incentive Warrants have been granted since February 2006. All compensation costs attributable to these awards have been recognized in prior periods and all remaining awards were exercised in November 2013. The following summary presents information regarding outstanding Stock Options as of June 30, 2016 , and the changes during the period: Number of Stock Options Weighted Average Exercise Price Aggregate Intrinsic Value(1) Weighted Average Remaining Contractual Term (in years) Stock Options outstanding at July 1, 2015 91,061 $ 2.50 Exercised (50,000 ) 2.55 Expired (5,830 ) 4.02 Stock Options outstanding at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Vested at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Exercisable at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 (1) Based upon the difference between the market price of our common stock on the last trading date of the period ( $5.47 as of June 30, 2016 ) and the Stock Option exercise price of in-the-money Stock Options. For the year ended June 30, 2016 , there were 50,000 Stock Options exercised with an aggregate intrinsic value of $131,000 . For the year ended June 30, 2015, there were 87,000 Stock Options exercised, with an aggregate intrinsic value of $501,810 . For the year ended June 30, 2014, there were 4,644,759 Stock Options and Incentive Warrants exercised with an aggregate intrinsic value of $47,504,114 . No stock options vested during the years ended June 30, 2016 , 2015 , and 2014 . Restricted Stock and Contingent Restricted Stock Prior to August 28, 2014, all Restricted Stock grants contained a four -year vesting period based solely on service. Restricted Stock which vests based solely on service is valued at the fair market value on the date of grant and are amortized over the service period. In August 2014 and in December 2015, the Company awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were issued on the date of grant, whereas the Contingent Restricted Stock are reserved from the Plan, but will be issued only upon the attainment of specified performance-based or market-based vesting provisions. Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four -year term. As of June 30, 2016 , certain performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period. Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. During the fiscal year ended June 30, 2016 , we granted market-based awards with fair values ranging from $2.93 to $5.07 , all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance. During the fiscal year ended June 30, 2015, we granted market-based awards with fair values ranging from $4.26 to $8.40 and with expected vesting periods of 3.30 years to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service. In December 2015, one employee resigned and three others left the Company when we restructured our artificial lift technology operations. As a result 31,467 restricted shares and 14,212 contingent restricted shares were forfeited. Also in connection with the restructuring, at the Company’s request in February 2016, certain employees agreed to voluntarily relinquish 31,307 restricted performance-based shares and 15,654 contingent performance-based shares in exchange for 22,016 shares of service-based restricted stock subject to vesting in three annual tranches ending on August 28, 2018. Unvested Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Service-based awards 224,515 $ 7.08 Performance-based awards 89,079 7.17 Market-based awards 93,254 5.50 Unvested at June 30, 2016 406,848 $ 6.74 The following table sets forth the Restricted Stock transactions for the year ended June 30, 2016 : Number of Restricted Shares Weighted Average Grant-Date Fair Value Unamortized Compensation Expense at June 30, 2016 Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 262,227 $ 9.37 $ — Service-based awards granted 164,610 5.84 Performance-based awards granted 64,752 6.09 Market-based awards granted 64,752 4.58 Vested (86,719 ) 8.73 Forfeited (62,774 ) 9.72 Unvested at June 30, 2016 406,848 $ 6.74 $ 1,536,125 2.6 During the years ended June 30, 2016 , 2015 , and 2014 , there were 86,719 , 91,306 , and 277,198 shares of Restricted Stock that vested with a total grant date fair value of $757,229 , $766,970 , and $1,796,243 , respectively. Unvested Contingent Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Performance-based awards 44,542 $ 7.17 Market-based awards 46,630 3.34 Unvested at June 30, 2016 91,172 $ 5.21 The following table summarizes Contingent Restricted Stock activity: Number of Weighted Unamortized Compensation Expense at June 30, 2016 (1) Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 56,286 $ 8.20 Performance-based awards granted 32,376 6.09 Market-based awards granted 32,376 2.93 Forfeited (29,866 ) $ 9.33 Unvested at June 30, 2016 91,172 $ 5.21 $ 107,219 2.8 (1) Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes. Stock-based Compensation Expense For the years ended June 30, 2016 , 2015 , and 2014 , we recognized stock-based compensation expense related to Restricted Stock, Contingent Restricted Stock grants, and Stock Option grants of $1,809,548 , $943,653 , and $1,728,687 , respectively. Included in these amounts are stock-based compensation expense of $59,339 for the year ended June 30, 2016 and $376,365 for the year ended June 30, 2014 that were reflected in restructuring charges.

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash Flow Information	12 Months Ended
	Jun. 30, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental Disclosure of Cash Flow Information	Supplemental Disclosure of Cash Flow Information Our supplemental disclosures of cash flow information for the years ended June 30, 2016 , 2015 , and 2014 are as follows: June 30, 2016 2015 2014 Income taxes paid $ 540,000 $ 220,000 $ 755,941 Income tax refunds 1,556,999 331,733 — Non-cash transactions: Increase (decrease) in accrued purchases of property and equipment (2,250,048 ) 5,422,566 (183,766 ) Deferred loan costs charged to oil and gas property costs 107,196 — — Oil and natural gas property costs attributable to the recognition of asset retirement obligations 140,151 576,039 66,976 Mengel working interest acquired in Delhi Field litigation settlement 596,500 — — Royalty rights acquired through non-monetary exchange of patent and trademark assets 108,512 — — Previously acquired Company shares swapped by holders to pay stock option exercise price $ 76,500 $ — $ 618,606 Accrued purchases of treasury stock (170,283 ) 170,283 —

Income Taxes

Income Taxes	12 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2016 , 2015 and 2014 . We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending June 30, 2013 through June 30, 2015 for federal tax purposes and for the years ended June 30, 2011 through June 30, 2015 for state tax purposes. The components of our income tax provision (benefit) are as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current: Federal $ 8,731,290 $ 1,413,296 $ 386,018 State 264,254 608,436 161,168 Total current income tax provision 8,995,544 2,021,732 547,186 Deferred: Federal 541,891 1,282,059 1,319,727 State 33,344 140,430 25,085 Total deferred income tax provision 575,235 1,422,489 1,344,812 $ 9,570,779 $ 3,444,221 $ 1,891,998 The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate, currently 34% , to the income tax provision in our financial statements. The effective tax rate for 2016 is less than the statutory rate primarily due to the benefit derived from statutory depletion in excess of tax basis. The effective tax rates for 2015 and 2014 exceed the statutory rate as a result of state income taxes, primarily in the state of Louisiana, with smaller adjustments related to stock-based compensation and other permanent differences. June 30, 2016 June 30, 2015 June 30, 2014 Income tax provision (benefit) computed at the statutory federal rate $ 11,638,588 $ 2,868,267 $ 1,866,366 Reconciling items: Depletion in excess of basis (2,242,620 ) — — State income taxes, net of federal tax benefit 196,415 595,708 189,081 Permanent differences related to stock-based compensation — — (155,817 ) Other permanent differences (21,604 ) (19,754 ) (7,632 ) Income tax provision $ 9,570,779 $ 3,444,221 $ 1,891,998 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are classified as either current or noncurrent on the balance sheet based on the classification of the related asset or liability for financial reporting purposes. Deferred tax assets and liabilities not related to specific assets or liabilities on the financial statements are classified according to the expected reversal date of the temporary difference or the expected utilization date for tax attribute carryforwards. Asset (Liability) June 30, 2016 June 30, 2015 June 30, 2014 Deferred tax assets: Non-qualified stock-based compensation $ 553,182 $ 173,647 $ 134,469 Net operating loss carry-forwards 386,808 400,288 427,249 AMT credit carry-forward* — 701,254 701,254 Other 130,947 91,113 165,775 Gross deferred tax assets 1,070,937 1,366,302 1,428,747 Valuation allowance (292,446 ) (292,446 ) (292,446 ) Total deferred tax assets 778,491 1,073,856 1,136,301 Deferred tax liability: Oil and natural gas properties (12,513,863 ) (12,233,993 ) (10,873,949 ) Total deferred tax liability (12,513,863 ) (12,233,993 ) (10,873,949 ) Net deferred tax liability $ (11,735,372 ) $ (11,160,137 ) $ (9,737,648 ) _______________________________________________________________________________ * In fiscal 2016 we used our total AMT credit carry-forward of $901,545 . Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation. The above assets and liabilities are present on the balance sheet as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current deferred tax asset $ 105,321 $ 82,414 $ 159,624 Non-current deferred tax liability 11,840,693 11,242,551 9,897,272 Net liability 11,735,372 11,160,137 9,737,648 As of June 30, 2016 , we had a federal tax loss carryforward of approximately $1.2 million that we acquired through the reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. We will be able to utilize a maximum of $0.3 million of these carryforwards in equal annual amounts of $39,648 through 2023 and the balance is not able to be utilized based on the provisions of IRC Section 382. We have recorded a valuation allowance for the portion of our net operating loss that is limited by IRC Section 382. During fiscal 2016 we utilized the remaining amount of $25.3 million of net operating losses ("NOL's") created primarily from tax deductions in excess of book deductions related to the exercise of non-qualified stock options and incentive warrants in fiscal 2014. NOL's related to such stock-based awards had not affected our future tax provision for financial reporting purposes, nor had it been recognized as a deferred tax asset for these future benefits. In fiscal 2016, 2015 and 2014, we recognized a tax benefit for utilization of these NOL's to offset cash taxes that would otherwise have been payable as an increase in additional paid in capital, in amounts of $9,650,657 , $1,633,946 and $509,096 respectively. In late September 2015, we received a $1.5 million refund payment of cash taxes paid to the State of Louisiana over a three-year period ended June 30, 2014. We also received $57,467 from the State of Louisiana for interest on the refund and recorded it as a reduction of current income tax expense. This carryback of tax losses resulted from the exercise of stock options and incentive warrants in fiscal 2014 and, accordingly, we recognized this benefit as an increase in additional paid-in capital for financial reporting purposes. This carryback utilized approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes. The remaining balance of this net loss carryforward in Louisiana was utilized in the tax return for the year ended June 30, 2015. In addition, as of June 30, 2016, the Company has an estimated carryforward of percentage depletion in excess of basis of approximately $5.0 million . These future deductions are limited to 65% of taxable income in any period.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions On June 30, 2011, we entered into a Technology Assignment Agreement with the Company’s Senior Vice President of Operations to acquire exclusive, perpetual, non-cancelable rights to the patented artificial lift technology he developed while employed by the Company. Under the agreement, he was paid a fee when the technology was employed. For the years ended June 30, 2016, 2015 and 2014, we made payments of $0 , $26,579 and $10,113 , respectively, under the agreement, while he served as an officer of the Company. Our obligations with respect to this agreement were terminated in December 2015 in connection with the transfer of our artificial lift technology operations to Well Lift Inc.

Net Income Per Share

Net Income Per Share	12 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Net Income Per Share	Net Income Per Share The following table sets forth the computation of basic and diluted net income per share: June 30, 2016 2015 2014 Numerator Net income attributable to common shareholders $ 23,986,060 $ 4,317,555 $ 2,923,011 Denominator Weighted average number of common shares – Basic 32,810,375 32,817,456 30,895,832 Effect of dilutive securities: Contingent restricted stock grants 9,378 4,422 — Stock Options 41,478 102,140 1,668,235 Total weighted average dilutive securities 50,856 106,562 1,668,235 Weighted average number of common shares and dilutive potential common shares used in diluted EPS 32,861,231 32,924,018 32,564,067 Net income per common share – Basic $ 0.73 $ 0.13 $ 0.09 Net income per common share – Diluted $ 0.73 $ 0.13 $ 0.09 The following were reflected in the calculation of diluted earnings per share as of June 30, 2016 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 91,172 Stock Options 2.19 35,231 Total $ 0.61 126,403 The following were reflected in the calculation of diluted earnings per share as of June 30, 2015 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 56,286 Stock Options $ 2.50 91,061 Total $ 1.55 147,347 The following were reflected in the calculation of diluted earnings per share as of June 30, 2014 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Stock Options $ 2.08 178,061

Credit Agreements

Credit Agreements	12 Months Ended
	Jun. 30, 2016
Debt Disclosure [Abstract]
Credit Agreements	Credit Agreements Senior Secured Credit Agreement On April 11, 2016, the Company entered into a new three -year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million . The Facility replaces the Company's previous unsecured credit facility which was set to expire on April 29, 2016 and was terminated in early April. The initial borrowing base under the Facility was set at $10 million and the Company has no outstanding borrowings. Proceeds from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations. The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000 , and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either Libor plus 2.75% or the Prime Rate, as defined, plus 1.00% . The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00 , (b) a debt service coverage ratio of not less than 1.10 to 1.00 , and (c) a consolidated tangible net worth of not less than $40 million , all as defined under the Facility. In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $155,009 as of June 30, 2016. Unsecured Revolving Credit Agreement On February 29, 2012, the Company and a commercial bank entered into an unsecured credit agreement with a four year term. The agreement had provided $5 million of availability, which the Company never utilized. The original expiration date was extended to April 29, 2016. In connection with this agreement, the Company had incurred $179,468 of debt issuance costs. Such costs had been capitalized in Other Assets and have been completely amortized to expense.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies On December 13, 2013, Evolution Petroleum Corporation and its wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp. (collectively, “Evolution”) filed a lawsuit in the 133 rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi field in northeast Louisiana. On June 24, 2016, Evolution entered into a settlement agreement with Denbury to resolve all outstanding disputes and claims between the parties, including claims related to the pending litigation between Evolution and Denbury with respect to the Delhi field. Pursuant to the settlement, the parties dismissed with prejudice all such claims between them with respect to such litigation. In addition to clarifying certain aspects of the parties' ongoing relationship, the settlement resolves (a) claims by Evolution in connection with the June 2013 incident at the Delhi field involving a release of well fluids (the “June 2013 Incident”); (b) disputes regarding the occurrence, determination, timing, nature and terms of “payout” and Evolution's related reversionary interest in the Delhi Field; and (c) any claims by Denbury related to the purchase by Denbury of its original Delhi field interest from the Company. Under the terms of the settlement, Evolution retains any and all rights under its existing agreements with Denbury regarding indemnification for any costs which are asserted or arise subsequent to the effective date of the settlement and which relate to periods prior to reversion of its working interest, including any such costs related to the June 2013 Incident. See Note 3 — Delhi Field Litigation Settlement. On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed certain claims against NGS Sub Corp. The plaintiffs subsequently filed an amended petition naming NGS Sub Corp. and the Company as defendants. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. Various pretrial motions filed on behalf of multiple parties were recently decided by the court and discovery is in process. We will continue to vigorously defend all claims by plaintiffs and consider the likelihood of a material loss to the Company in this matter to be remote. Lease Commitments. We had a non-cancelable lease for office space that expired on July 31, 2016. Late in fiscal 2016, the Company entered into a new non-cancelable office space with a three year term ending on May 31, 2019. Future minimum lease commitments as of June 30, 2016 under these operating leases are as follows: For the fiscal year ended June 30, 2017 $ 80,235 2018 73,073 2019 66,984 Total $ 220,292 Rent expense for the years ended June 30, 2016 , 2015 , and 2014 was $182,626 , $175,103 , and $174,229 , respectively. Capital Expenditures. See Note 6 for discussion of capital projects in progress and expected remaining capital commitments.

Concentrations of Credit Risk

Concentrations of Credit Risk	12 Months Ended
	Jun. 30, 2016
Risks and Uncertainties [Abstract]
Concentrations of Credit Risk	Concentrations of Credit Risk Major Customers. We market all of our oil and natural gas production from the properties we operate. We do not currently market our share of crude oil production from Delhi. Although we have the right to take our working interest production at Delhi in-kind, we are currently selling our oil under the Delhi operator's agreement with Plains Marketing L.P. for the delivery of our oil to a pipeline at the field. The majority of our operated gas, oil and condensate production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more our net oil and natural gas revenues during the years ended June 30, 2016 , 2015 , and 2014 . The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations. Year Ended June 30, Customer 2016 2015 2014 Plains Marketing L.P. (includes Delhi production) 99 % 99 % 96 % Enterprise Crude Oil LLC — % — % 2 % Flint Hills — % — % 1 % ETC Texas Pipeline, LTD. — % — % 1 % All others 1 % 1 % — % Total 100 % 100 % 100 % Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales to third parties in the oil and natural gas industry. Our concentration of customers in this industry may impact our overall credit risk. Cash and Cash Equivalents and Certificates of Deposit. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents in high quality money market funds. At times, cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation ("FDIC"). Our certificates of deposit are below or at the maximum federally insured limit set by the FDIC.

Retirement Plan

Retirement Plan	12 Months Ended
	Jun. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Retirement Plan	Retirement Plan We have a Company sponsored 401(k) Retirement Plan ("Plan") which covers all full-time employees. We currently match 100% of employees' contributions to the Plan, to a maximum of the first 6% of each participant's eligible compensation, with Company contributions fully vested when made. Our matching contributions to the Plan totaled $88,348 , $85,676 , and $116,873 for the years ended June 30, 2016 , 2015 , and 2014 , respectively.

Derivatives

Derivatives	12 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives In early June 2015, the Company began using derivative instruments to reduce its exposure to crude oil price volatility for a substantial portion of its near-term forecasted production. The Company's objectives for this program were to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The Company uses both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes. The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedgin g ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in income. Given cost and complexity considerations, the Company did not elect to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instruments would be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings. These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value derivative instruments where the Company is in a net asset position with its counterparty as of June 30, 2016 totaled $14,132 . Refer to Note 22–Fair Value Measurement for derivative asset and derivative liability balances before offsetting. The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. For the year ended June 30, 2016, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $3,439,229 consisting of a realized gain of $3,315,123 on settled derivatives and an unrealized gain of $124,106 on unsettled derivatives. For the year ended June 30, 2015 , the Company recorded in the consolidated statement of operations a net unrealized loss on unsettled derivatives of $109,974 . The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2016 . Period Type of Contract Volumes (in Bbls./day) Weighted Average Floor Price per Bbl. Weighted Average Ceiling Price per Bbl. Weighted Average Collar Spread per Bbl. Months of July 2016 through September 2016 Costless Collar 600 $45.00 $55.00 $10.00 Subsequent to June 30, 2016 , the Company's July and August collars expired without settlement as the respective NYMEX prices for those months fell between the floor and ceiling prices.

Fair Value Measurement

Fair Value Measurement	12 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. Fair Value of Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2016 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: June 30, 2016 Asset (Liability) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheets Current derivative assets $ 45,263 $ (31,131 ) $ 14,132 Current derivative liabilities (31,131 ) 31,131 — Total $ 14,132 $ — $ 14,132 The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparties credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.

Supplemental Disclosures about

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)	12 Months Ended
	Jun. 30, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)	Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) Costs incurred for oil and natural gas property acquisition, exploration and development activities The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $140,151 , $576,039 and $66,976 during the years ended June 30, 2016 , 2015 , and 2014 , respectively. For the Years Ended June 30, 2016 2015 2014 Oil and Natural Gas Activities Property acquisition costs: Proved property $ — $ — $ — Unproved property (a) 596,500 — 47,344 Exploration costs — — 757,423 Development costs 19,093,200 10,975,637 18,566 Total costs incurred for oil and natural gas activities $ 19,689,700 $ 10,975,637 $ 823,333 (a) As described in Note 3 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500 . This cost is included in properties subject to amortization. Estimated Net Quantities of Proved Oil and Natural Gas Reserves The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2016 , 2015 , and 2014 , which requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce. Proved oil and natural gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows: Crude Oil (Bbls) Natural Gas Liquids (Bbls) Natural Gas (Mcf) BOE Proved developed and undeveloped reserves: June 30, 2013 12,782,755 979,885 22,797 13,766,440 Revisions of previous estimates (a) (1,919,052 ) 1,269,588 2,412,677 (247,350 ) Improved recovery, extensions and discoveries 17,146 32,731 498,044 132,884 Sales of minerals in place (184,722 ) — — (184,722 ) Production (sales volumes) (169,783 ) (3,516 ) (26,655 ) (177,742 ) June 30, 2014 10,526,344 2,278,688 2,906,863 13,289,510 Revisions of previous estimates (b) (64,074 ) 156,195 (2,894,703 ) (390,330 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (450,294 ) (1,288 ) (7,221 ) (452,786 ) June 30, 2015 10,011,976 2,433,595 4,939 12,446,394 Revisions of previous estimates (c) (765,385 ) (198,233 ) (3,319 ) (964,171 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (658,041 ) (491 ) (1,620 ) (658,802 ) June 30, 2016 8,588,550 2,234,871 — 10,823,421 Proved developed reserves: June 30, 2013 10,077,522 8,539 22,797 10,089,861 June 30, 2014 7,858,224 32,164 481,042 7,970,562 June 30, 2015 7,347,231 1,572 4,939 7,349,626 June 30, 2016 7,168,249 — — 7,168,249 Proved undeveloped reserves: June 30, 2013 2,705,233 971,346 — 3,676,579 June 30, 2014 2,668,120 2,246,524 2,425,821 5,318,948 June 30, 2015 2,664,745 2,432,023 — 5,096,768 June 30, 2016 1,420,301 2,234,871 — 3,655,172 (a) Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO 2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes. (b) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well. (c) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period. Standardized Measure of Discounted Future Net Cash Flows Future oil and natural gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas ("ASC 932"). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves. The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2016 , 2015 , and 2014 are as follows: For the Years Ended June 30, 2016 2015 2014 Future cash inflows $ 383,491,193 $ 807,030,282 $ 1,193,515,075 Future production costs and severance taxes (179,182,565 ) (309,225,333 ) (475,387,931 ) Future development costs (16,595,047 ) (49,691,006 ) (46,154,178 ) Future income tax expenses (45,713,438 ) (123,888,665 ) (195,581,510 ) Future net cash flows 142,000,143 324,225,278 476,391,456 10% annual discount for estimated timing of cash flows (64,042,824 ) (165,028,739 ) (250,313,784 ) Standardized measure of discounted future net cash flows $ 77,957,319 $ 159,196,539 $ 226,077,672 Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials. Year Ended June 30, 2016 2015 2014 Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) NYMEX prices used in determining future cash flows $ 42.91 n/a $ 71.88 $ 3.44 $ 100.37 $ 4.10 There were no natural gas reserves in 2016. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant. A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows: For the Years Ended June 30, 2016 2015 2014 Balance, beginning of year $ 159,196,539 $ 226,077,672 $ 307,220,699 Net changes in sales prices and production costs related to future production (120,832,747 ) (88,043,095 ) (73,439,526 ) Changes in estimated future development costs 74,991 (9,585,405 ) 9,848,614 Sales of oil and gas produced during the period, net of production costs (17,079,363 ) (18,538,016 ) (16,479,934 ) Net change due to extensions, discoveries, and improved recovery — — 775,574 Net change due to revisions in quantity estimates (18,821,014 ) (9,391,321 ) (23,757,788 ) Net change due to sales of minerals in place — — (3,150,277 ) Development costs incurred during the period 16,327,883 7,785,095 — Accretion of discount 21,870,650 31,974,540 45,896,187 Net change in discounted income taxes 36,598,239 34,157,767 58,073,450 Net changes in timing of production and other (a) 622,141 (15,240,698 ) (78,909,327 ) Balance, end of year $ 77,957,319 $ 159,196,539 $ 226,077,672 (a) Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014.

Selected Quarterly Financial Da

Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Jun. 30, 2016
Quarterly Financial Information Disclosure [Abstract]
Selected Quarterly Financial Data (Unaudited)	Selected Quarterly Financial Data (Unaudited) The following table presents summarized quarterly financial information for the years ended June 30, 2016 and 2015 : 2016 First Second (1) Third Fourth (2) Revenues $ 7,379,406 $ 6,622,927 $ 5,106,735 $ 7,240,434 Operating income (loss) 1,846,498 (454,987 ) (681,147 ) 954,823 Net income (loss) available to common shareholders $ 2,923,652 $ 654,697 $ (298,183 ) $ 20,705,894 Basic net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 Diluted net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 2015 First Second (3) Third Fourth Revenues $ 4,004,827 $ 7,708,067 $ 7,064,689 $ 9,063,682 Operating income 1,840,866 2,162,294 1,245,990 3,334,547 Net income available to common shareholders $ 960,435 $ 1,071,342 $ 566,011 $ 1,719,767 Basic net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 Diluted net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 (1) Includes $1.3 million restructuring charge. (2) Includes gain on settlement of Delhi field litigation of $28.1 million . (3) Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field.

Summary of Significant Accoun32

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. As a result of the separation of our GARP ® artificial lift technology operations discussed in Note 8, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified as appropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues included crude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells that utilized the technology, together with service revenues derived from the use of the Company’s technology in third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oil and gas production costs and cost of artificial lift technology services.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts	Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of joint interest owner obligations due within 30 days of the invoice date, accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2016 and 2015 , no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties	Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.
Limitation on Capitalized Costs	Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent , and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 -month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Tests did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2016 , 2015 or 2014 .
Other Property and Equipment	Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furniture and equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years . The assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred.
Deferred Financing Costs	Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Asset Retirement Obligations	Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Fair Value of Financial Instruments	Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors.
Stock-based Compensation	Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense. Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricing model to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fair value is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that the recipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service.
Revenue Recognition	Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment. Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues.
Derivative Instruments	Derivative Instruments. The Company uses derivative transactions to reduce its exposure to oil price volatility. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to a ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as a result of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes.
Depreciation, Depletion and Amortization	Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computer equipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment.
Intangible Assets - Intellectual Property	Intangible Assets - Intellectual Property. The Company has capitalized the external costs, consisting primarily of legal costs, related to securing its patents and trademarks. The costs related to patents were amortized over the remaining patent life which was less than the expected useful life of each patent. Trademarks have a perpetual life and were not amortized.
Income Taxes	Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.
Earnings (loss) per share	Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common shares outstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants, and contingent restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method. Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shall be assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPS computation. Potentially dilutive common shares are excluded from the computation if their effect is anti-dilutive.
Recent Accounting Pronouncements	Recent Accounting Pronouncements. In August 2015, the FASB issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 would have been effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provided for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements, if any. In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” as part of their simplification initiatives. The standard requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The update is effective for public company annual reporting periods beginning after December 15, 2016, and may be adopted prospectively or retrospectively with early adoption permitted. The Company plans to early adopt this standard the first quarter of year ended June 30, 2017 and does not believe that adoption of this update will have a material impact on our results of operations, financial position or cash flows. On February 25, 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than 12 months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our condensed consolidated financial statements. On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company plans to early adopt this standard during the first quarter of the year ended June 30, 2017. The adoption of this standard will result in all excess tax benefits or deficiencies being recognized as tax expense or benefit in the reporting period they occur regardless of whether the benefit reduces taxes payable in the current period. On the statement of cash flows excess tax benefits or deficiencies will be classified along with other income tax as an operating activity and cash paid by the Company when directly withholding shares for tax withholding purposes will continue to be classified as a financing activity. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements, but does not expect the impact of adoption to be material.

Receivables (Tables)

Receivables (Tables)	12 Months Ended
	Jun. 30, 2016
Receivables [Abstract]
Schedule of receivables	As of June 30, 2016 and June 30, 2015 our receivables consisted of the following: June 30, June 30, Receivables from oil and gas sales $ 2,637,593 $ 3,122,155 Other 595 318 Total receivables $ 2,638,188 $ 3,122,473

Prepaid Expenses and Other Cu34

Prepaid Expenses and Other Current Assets (Tables)	12 Months Ended
	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of prepaid expenses and other current assets	As of June 30, 2016 and June 30, 2015 our prepaid expenses and other current assets consisted of the following: June 30, June 30, Prepaid insurance $ 168,681 $ 178,994 Prepaid federal and state income taxes — 22,542 Equipment inventory (a) — 81,538 Retainers and deposits 30,568 26,978 Other prepaid expenses 52,500 59,352 Prepaid expenses and other current assets $ 251,749 $ 369,404 (a) As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged to restructuring costs as part of the separation of our artificial lift technology operations

Property and Equipment (Tables)

Property and Equipment (Tables)	12 Months Ended
	Jun. 30, 2016
Property, Plant and Equipment [Abstract]
Schedule of oil and natural gas properties and other property and equipment	As of June 30, 2016 and June 30, 2015 , our oil and natural gas properties and other property and equipment consisted of the following: June 30, June 30, Oil and natural gas properties: Property costs subject to amortization $ 77,408,353 $ 57,718,653 Less: Accumulated depreciation, depletion, and amortization (17,437,890 ) (12,531,767 ) Unproved properties not subject to amortization — — Oil and natural gas properties, net 59,970,463 45,186,886 Other property and equipment: Furniture, fixtures and office equipment, at cost 228,752 287,680 Artificial lift technology equipment, at cost 7,000 319,994 Less: Accumulated depreciation (207,103 ) (330,918 ) Other property and equipment, net $ 28,649 $ 276,756

Other Assets (Tables)

Other Assets (Tables)	12 Months Ended
	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of other assets	As of June 30, 2016 and June 30, 2015 our other assets consisted of the following: June 30, June 30, Royalty rights 108,512 — Less: Accumulated amortization of royalty rights (6,782 ) — Investment in Well Lift Inc., at cost 108,750 — Deferred loan costs 168,972 337,078 Less: Accumulated amortization of deferred loan costs (13,963 ) (147,057 ) Trademarks — 44,803 Patent costs — 538,276 Less: Accumulated amortization of patent costs — (47,063 ) Other assets, net $ 365,489 $ 726,037

Restructuring (Tables)

Restructuring (Tables)	12 Months Ended
	Jun. 30, 2016
Restructuring and Related Activities [Abstract]
Schedule of restructuring reserve by type of cost	Our current estimate of remaining restructuring obligations as of June 30, 2016 is as follows: Type of Cost December 31, Payments Adjustments to Cost June 30, Salary expense $ 530,387 $ (176,796 ) $ — $ 353,591 Payroll taxes and benefits expense 98,479 (32,582 ) — 65,897 Accrued liability for restructuring costs $ 628,866 $ (209,378 ) $ — $ 419,488 Our disposition of the accrued restructuring charges is reflected in the following schedule: Type of Cost Balance at December 31, Payments Adjustment to Cost June 30, Salary expense $ 615,721 $ (615,721 ) $ — $ — Incentive compensation costs 185,525 (185,525 ) — — Payroll taxes and benefits expense 154,575 (110,144 ) (44,431 ) — Accrued liability for restructuring costs $ 955,821 $ (911,390 ) $ (44,431 ) $ —

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Jun. 30, 2016
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	As of June 30, 2016 and June 30, 2015 our other current liabilities consisted of the following: June 30, June 30, Accrued incentive and other compensation $ 999,172 $ 578,910 Accrued restructuring charges 419,488 — Asset retirement obligations due within one year 201,896 57,223 Accrued royalties, including suspended accounts 49,580 75,164 Accrued franchise taxes 62,834 94,885 Payable for settled derivatives 318,708 — Accrued - other 46,273 49,191 Accrued liabilities and other $ 2,097,951 $ 855,373

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Schedule of reconciliation of the beginning and ending asset retirement obligation	The following is a reconciliation of the beginning and ending asset retirement obligation for the years ended June 30, 2016 and 2015 : Years Ended 2016 2015 Asset retirement obligations—beginning of period $ 772,990 $ 352,215 Liabilities incurred (a) 28,505 564,019 Liabilities settled — (137,604 ) Liabilities sold — (52,526 ) Accretion of discount 49,054 34,866 Revisions to previous estimates 111,647 12,020 Asset retirement obligations — end of period 962,196 772,990 Less: current asset retirement obligations (201,896 ) (57,223 ) Long-term portion of asset retirement obligations $ 760,300 $ 715,767 (a) Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest.

Stock-Based Incentive Plan (Tab

Stock-Based Incentive Plan (Tables)	12 Months Ended
	Jun. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of information regarding outstanding Stock Options and Incentive Warrants and the changes during the fiscal year	The following summary presents information regarding outstanding Stock Options as of June 30, 2016 , and the changes during the period: Number of Stock Options Weighted Average Exercise Price Aggregate Intrinsic Value(1) Weighted Average Remaining Contractual Term (in years) Stock Options outstanding at July 1, 2015 91,061 $ 2.50 Exercised (50,000 ) 2.55 Expired (5,830 ) 4.02 Stock Options outstanding at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Vested at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Exercisable at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 (1) Based upon the difference between the market price of our common stock on the last trading date of the period ( $5.47 as of June 30, 2016 ) and the Stock Option exercise price of in-the-money Stock Options.
Schedule of Restricted Stock transactions	The following table sets forth the Restricted Stock transactions for the year ended June 30, 2016 : Number of Restricted Shares Weighted Average Grant-Date Fair Value Unamortized Compensation Expense at June 30, 2016 Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 262,227 $ 9.37 $ — Service-based awards granted 164,610 5.84 Performance-based awards granted 64,752 6.09 Market-based awards granted 64,752 4.58 Vested (86,719 ) 8.73 Forfeited (62,774 ) 9.72 Unvested at June 30, 2016 406,848 $ 6.74 $ 1,536,125 2.6 Unvested Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Service-based awards 224,515 $ 7.08 Performance-based awards 89,079 7.17 Market-based awards 93,254 5.50 Unvested at June 30, 2016 406,848 $ 6.74 Unvested Contingent Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Performance-based awards 44,542 $ 7.17 Market-based awards 46,630 3.34 Unvested at June 30, 2016 91,172 $ 5.21 The following table summarizes Contingent Restricted Stock activity: Number of Weighted Unamortized Compensation Expense at June 30, 2016 (1) Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 56,286 $ 8.20 Performance-based awards granted 32,376 6.09 Market-based awards granted 32,376 2.93 Forfeited (29,866 ) $ 9.33 Unvested at June 30, 2016 91,172 $ 5.21 $ 107,219 2.8 (1) Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Supplemental Disclosure of Ca41

Supplemental Disclosure of Cash Flow Information (Tables)	12 Months Ended
	Jun. 30, 2016
Supplemental Cash Flow Elements [Abstract]
Schedule of supplemental disclosures of cash flow information	Our supplemental disclosures of cash flow information for the years ended June 30, 2016 , 2015 , and 2014 are as follows: June 30, 2016 2015 2014 Income taxes paid $ 540,000 $ 220,000 $ 755,941 Income tax refunds 1,556,999 331,733 — Non-cash transactions: Increase (decrease) in accrued purchases of property and equipment (2,250,048 ) 5,422,566 (183,766 ) Deferred loan costs charged to oil and gas property costs 107,196 — — Oil and natural gas property costs attributable to the recognition of asset retirement obligations 140,151 576,039 66,976 Mengel working interest acquired in Delhi Field litigation settlement 596,500 — — Royalty rights acquired through non-monetary exchange of patent and trademark assets 108,512 — — Previously acquired Company shares swapped by holders to pay stock option exercise price $ 76,500 $ — $ 618,606 Accrued purchases of treasury stock (170,283 ) 170,283 —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Schedule of components of income tax provision (benefit)	The components of our income tax provision (benefit) are as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current: Federal $ 8,731,290 $ 1,413,296 $ 386,018 State 264,254 608,436 161,168 Total current income tax provision 8,995,544 2,021,732 547,186 Deferred: Federal 541,891 1,282,059 1,319,727 State 33,344 140,430 25,085 Total deferred income tax provision 575,235 1,422,489 1,344,812 $ 9,570,779 $ 3,444,221 $ 1,891,998
Schedule of reconciliation of statutory income tax expense to income tax provision	The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate, currently 34% , to the income tax provision in our financial statements. The effective tax rate for 2016 is less than the statutory rate primarily due to the benefit derived from statutory depletion in excess of tax basis. The effective tax rates for 2015 and 2014 exceed the statutory rate as a result of state income taxes, primarily in the state of Louisiana, with smaller adjustments related to stock-based compensation and other permanent differences. June 30, 2016 June 30, 2015 June 30, 2014 Income tax provision (benefit) computed at the statutory federal rate $ 11,638,588 $ 2,868,267 $ 1,866,366 Reconciling items: Depletion in excess of basis (2,242,620 ) — — State income taxes, net of federal tax benefit 196,415 595,708 189,081 Permanent differences related to stock-based compensation — — (155,817 ) Other permanent differences (21,604 ) (19,754 ) (7,632 ) Income tax provision $ 9,570,779 $ 3,444,221 $ 1,891,998
Schedule of components of deferred taxes	The above assets and liabilities are present on the balance sheet as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current deferred tax asset $ 105,321 $ 82,414 $ 159,624 Non-current deferred tax liability 11,840,693 11,242,551 9,897,272 Net liability 11,735,372 11,160,137 9,737,648 Asset (Liability) June 30, 2016 June 30, 2015 June 30, 2014 Deferred tax assets: Non-qualified stock-based compensation $ 553,182 $ 173,647 $ 134,469 Net operating loss carry-forwards 386,808 400,288 427,249 AMT credit carry-forward* — 701,254 701,254 Other 130,947 91,113 165,775 Gross deferred tax assets 1,070,937 1,366,302 1,428,747 Valuation allowance (292,446 ) (292,446 ) (292,446 ) Total deferred tax assets 778,491 1,073,856 1,136,301 Deferred tax liability: Oil and natural gas properties (12,513,863 ) (12,233,993 ) (10,873,949 ) Total deferred tax liability (12,513,863 ) (12,233,993 ) (10,873,949 ) Net deferred tax liability $ (11,735,372 ) $ (11,160,137 ) $ (9,737,648 ) _______________________________________________________________________________ * In fiscal 2016 we used our total AMT credit carry-forward of $901,545 . Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation.

Net Income Per Share (Tables)

Net Income Per Share (Tables)	12 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Schedule of computation of basic and diluted income (loss) per share	The following table sets forth the computation of basic and diluted net income per share: June 30, 2016 2015 2014 Numerator Net income attributable to common shareholders $ 23,986,060 $ 4,317,555 $ 2,923,011 Denominator Weighted average number of common shares – Basic 32,810,375 32,817,456 30,895,832 Effect of dilutive securities: Contingent restricted stock grants 9,378 4,422 — Stock Options 41,478 102,140 1,668,235 Total weighted average dilutive securities 50,856 106,562 1,668,235 Weighted average number of common shares and dilutive potential common shares used in diluted EPS 32,861,231 32,924,018 32,564,067 Net income per common share – Basic $ 0.73 $ 0.13 $ 0.09 Net income per common share – Diluted $ 0.73 $ 0.13 $ 0.09
Schedule of outstanding potentially dilutive securities	The following were reflected in the calculation of diluted earnings per share as of June 30, 2016 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 91,172 Stock Options 2.19 35,231 Total $ 0.61 126,403 The following were reflected in the calculation of diluted earnings per share as of June 30, 2015 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 56,286 Stock Options $ 2.50 91,061 Total $ 1.55 147,347 The following were reflected in the calculation of diluted earnings per share as of June 30, 2014 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Stock Options $ 2.08 178,061

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Schedule of future minimum lease commitments under the operating lease	Future minimum lease commitments as of June 30, 2016 under these operating leases are as follows: For the fiscal year ended June 30, 2017 $ 80,235 2018 73,073 2019 66,984 Total $ 220,292

Concentrations of Credit Risk (

Concentrations of Credit Risk (Tables)	12 Months Ended
	Jun. 30, 2016
Risks and Uncertainties [Abstract]
Schedule of customers from whom the entity derived 10 percent or more of net oil and natural gas revenues	Year Ended June 30, Customer 2016 2015 2014 Plains Marketing L.P. (includes Delhi production) 99 % 99 % 96 % Enterprise Crude Oil LLC — % — % 2 % Flint Hills — % — % 1 % ETC Texas Pipeline, LTD. — % — % 1 % All others 1 % 1 % — % Total 100 % 100 % 100 %

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Jun. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of crude oil derivative positions	The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2016 . Period Type of Contract Volumes (in Bbls./day) Weighted Average Floor Price per Bbl. Weighted Average Ceiling Price per Bbl. Weighted Average Collar Spread per Bbl. Months of July 2016 through September 2016 Costless Collar 600 $45.00 $55.00 $10.00

Fair Value Measurement (Tables)

Fair Value Measurement (Tables)	12 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of assets and liabilities measured on a recurring basis	The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2016 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: June 30, 2016 Asset (Liability) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheets Current derivative assets $ 45,263 $ (31,131 ) $ 14,132 Current derivative liabilities (31,131 ) 31,131 — Total $ 14,132 $ — $ 14,132

Supplemental Disclosures abou48

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) (Tables)	12 Months Ended
	Jun. 30, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities	The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $140,151 , $576,039 and $66,976 during the years ended June 30, 2016 , 2015 , and 2014 , respectively. For the Years Ended June 30, 2016 2015 2014 Oil and Natural Gas Activities Property acquisition costs: Proved property $ — $ — $ — Unproved property (a) 596,500 — 47,344 Exploration costs — — 757,423 Development costs 19,093,200 10,975,637 18,566 Total costs incurred for oil and natural gas activities $ 19,689,700 $ 10,975,637 $ 823,333
Schedule of estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves	Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows: Crude Oil (Bbls) Natural Gas Liquids (Bbls) Natural Gas (Mcf) BOE Proved developed and undeveloped reserves: June 30, 2013 12,782,755 979,885 22,797 13,766,440 Revisions of previous estimates (a) (1,919,052 ) 1,269,588 2,412,677 (247,350 ) Improved recovery, extensions and discoveries 17,146 32,731 498,044 132,884 Sales of minerals in place (184,722 ) — — (184,722 ) Production (sales volumes) (169,783 ) (3,516 ) (26,655 ) (177,742 ) June 30, 2014 10,526,344 2,278,688 2,906,863 13,289,510 Revisions of previous estimates (b) (64,074 ) 156,195 (2,894,703 ) (390,330 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (450,294 ) (1,288 ) (7,221 ) (452,786 ) June 30, 2015 10,011,976 2,433,595 4,939 12,446,394 Revisions of previous estimates (c) (765,385 ) (198,233 ) (3,319 ) (964,171 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (658,041 ) (491 ) (1,620 ) (658,802 ) June 30, 2016 8,588,550 2,234,871 — 10,823,421 Proved developed reserves: June 30, 2013 10,077,522 8,539 22,797 10,089,861 June 30, 2014 7,858,224 32,164 481,042 7,970,562 June 30, 2015 7,347,231 1,572 4,939 7,349,626 June 30, 2016 7,168,249 — — 7,168,249 Proved undeveloped reserves: June 30, 2013 2,705,233 971,346 — 3,676,579 June 30, 2014 2,668,120 2,246,524 2,425,821 5,318,948 June 30, 2015 2,664,745 2,432,023 — 5,096,768 June 30, 2016 1,420,301 2,234,871 — 3,655,172 (a) Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO 2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes. (b) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well. (c) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period.
Schedule of standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2016 , 2015 , and 2014 are as follows: For the Years Ended June 30, 2016 2015 2014 Future cash inflows $ 383,491,193 $ 807,030,282 $ 1,193,515,075 Future production costs and severance taxes (179,182,565 ) (309,225,333 ) (475,387,931 ) Future development costs (16,595,047 ) (49,691,006 ) (46,154,178 ) Future income tax expenses (45,713,438 ) (123,888,665 ) (195,581,510 ) Future net cash flows 142,000,143 324,225,278 476,391,456 10% annual discount for estimated timing of cash flows (64,042,824 ) (165,028,739 ) (250,313,784 ) Standardized measure of discounted future net cash flows $ 77,957,319 $ 159,196,539 $ 226,077,672
Schedule of NYMEX prices used in determining future cash flows	Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials. Year Ended June 30, 2016 2015 2014 Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) NYMEX prices used in determining future cash flows $ 42.91 n/a $ 71.88 $ 3.44 $ 100.37 $ 4.10
Schedule of changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves	A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows: For the Years Ended June 30, 2016 2015 2014 Balance, beginning of year $ 159,196,539 $ 226,077,672 $ 307,220,699 Net changes in sales prices and production costs related to future production (120,832,747 ) (88,043,095 ) (73,439,526 ) Changes in estimated future development costs 74,991 (9,585,405 ) 9,848,614 Sales of oil and gas produced during the period, net of production costs (17,079,363 ) (18,538,016 ) (16,479,934 ) Net change due to extensions, discoveries, and improved recovery — — 775,574 Net change due to revisions in quantity estimates (18,821,014 ) (9,391,321 ) (23,757,788 ) Net change due to sales of minerals in place — — (3,150,277 ) Development costs incurred during the period 16,327,883 7,785,095 — Accretion of discount 21,870,650 31,974,540 45,896,187 Net change in discounted income taxes 36,598,239 34,157,767 58,073,450 Net changes in timing of production and other (a) 622,141 (15,240,698 ) (78,909,327 ) Balance, end of year $ 77,957,319 $ 159,196,539 $ 226,077,672 (a) Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014.

Selected Quarterly Financial 49

Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Jun. 30, 2016
Quarterly Financial Information Disclosure [Abstract]
Summary of quarterly financial information	The following table presents summarized quarterly financial information for the years ended June 30, 2016 and 2015 : 2016 First Second (1) Third Fourth (2) Revenues $ 7,379,406 $ 6,622,927 $ 5,106,735 $ 7,240,434 Operating income (loss) 1,846,498 (454,987 ) (681,147 ) 954,823 Net income (loss) available to common shareholders $ 2,923,652 $ 654,697 $ (298,183 ) $ 20,705,894 Basic net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 Diluted net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 2015 First Second (3) Third Fourth Revenues $ 4,004,827 $ 7,708,067 $ 7,064,689 $ 9,063,682 Operating income 1,840,866 2,162,294 1,245,990 3,334,547 Net income available to common shareholders $ 960,435 $ 1,071,342 $ 566,011 $ 1,719,767 Basic net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 Diluted net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 (1) Includes $1.3 million restructuring charge. (2) Includes gain on settlement of Delhi field litigation of $28.1 million . (3) Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field.

Summary of Significant Accoun50

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Accounting Policies [Abstract]
Allowance for doubtful accounts	$ 0	$ 0
Oil and natural gas properties
Limitation on Capitalized Costs
Discount rate for present value (as a percent)	10.00%
Period considered for computing unweighted arithmetic average of oil and natural gas prices (in months)	12 months
Other Property and Equipment | Minimum
Other Property and Equipment
Expected lives of the individual assets or group of assets	3 years
Other Property and Equipment | Maximum
Other Property and Equipment
Expected lives of the individual assets or group of assets	7 years

Dehli Field Litigation Settle51

Dehli Field Litigation Settlement (Details) - USD ($)	Jul. 01, 2016	Jun. 24, 2016	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Loss Contingencies [Line Items]
Delhi field litigation settlement gain			$ 28,096,500	$ 0	$ 0
Fair value of litigation settlement			596,500	$ 0	$ 0
Dehli Field Litigation
Loss Contingencies [Line Items]
Delhi field litigation settlement gain			$ 28,100,000
Dehli Field Litigation | Denbury Resources, Inc
Loss Contingencies [Line Items]
Delhi field litigation settlement gain		$ 28,100,000
Proceeds from litigation		$ 27,500,000
Working interest in Mengal Sand Interval		23.90%
Fair value of litigation settlement		$ 596,500
Dehli Field Litigation | Denbury Resources, Inc | Subsequent Event
Loss Contingencies [Line Items]
Overriding royalty interest in Holt-Bryant	0.2226%
Dehli Field Litigation | Denbury Resources, Inc | Level 2
Loss Contingencies [Line Items]
Fair value of litigation settlement		$ 596,500

Receivables (Details)

Receivables (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Receivables [Abstract]
Receivables from oil and gas sales	$ 2,637,593	$ 3,122,155
Other	595	318
Total receivables	$ 2,638,188	$ 3,122,473

Prepaid Expenses and Other Cu53

Prepaid Expenses and Other Current Assets (Details) - USD ($)		Jun. 30, 2016	Jun. 30, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance		$ 168,681	$ 178,994
Prepaid federal and state income taxes		0	22,542
Equipment inventory	[1]	0	81,538
Retainers and deposits		30,568	26,978
Other prepaid expenses		52,500	59,352
Prepaid expenses and other current assets		$ 251,749	$ 369,404
[1]	As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged to restructuring costs as part of the separation of our artificial lift technology operations.

Property and Equipment - Summar

Property and Equipment - Summary of Property and Equipment (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Oil and natural gas properties:
Property costs subject to amortization	$ 77,408,353	$ 57,718,653
Less: Accumulated depreciation, depletion, and amortization	(17,437,890)	(12,531,767)
Unproved properties not subject to amortization	0	0
Oil and natural gas properties, net	59,970,463	45,186,886
Other property and equipment:
Furniture, fixtures and office equipment, at cost	228,752	287,680
Artificial lift technology equipment, at cost	7,000	319,994
Less: Accumulated depreciation	(207,103)	(330,918)
Other property and equipment, net	$ 28,649	$ 276,756

Property and Equipment - Narrat

Property and Equipment - Narrative (Details) - USD ($)	Jun. 24, 2016	Oct. 24, 2014	Dec. 01, 2013	Nov. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Property, Plant and Equipment [Line Items]
Fair value of litigation settlement					$ 596,500	$ 0	$ 0
Capital costs charged to expense					$ 5,165,120	3,615,737	1,228,685
Percentage of net profits from production					25.00%
Installation costs of artificial lift technology						217,733	377,943
Additional depreciation						275,682
Proceeds from asset sales					$ 0	$ 398,242	$ 542,347
Denbury Resources, Inc | Dehli Field Litigation
Property, Plant and Equipment [Line Items]
Working interest in Mengal Sand Interval	23.90%
Fair value of litigation settlement	$ 596,500
Artificial lift equipment
Property, Plant and Equipment [Line Items]
Capital costs charged to expense				$ 210,392
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Proceeds from asset sales		$ 389,165	$ 402,500
Delhi Field
Property, Plant and Equipment [Line Items]
Capital expenditures					19,000,000
NGL Plant Project
Property, Plant and Equipment [Line Items]
Capital expenditures					16,400,000
Incurred costs on a cumulative basis					21,500,000
Total authorized commitment					24,600,000
Remaining balance of authorized commitment					$ 3,100,000

Other Assets (Details)

Other Assets (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Royalty rights	$ 108,512	$ 0
Less: Accumulated amortization of royalty rights	(6,782)	0
Investment in Well Lift Inc., at cost	108,750	0
Deferred loan costs	168,972	337,078
Less: Accumulated amortization of deferred loan costs	(13,963)	(147,057)
Trademarks	0	44,803
Patent costs	0	538,276
Less: Accumulated amortization of patent costs	0	(47,063)
Other assets, net	$ 365,489	$ 726,037

Other Assets - Additional Infor

Other Assets - Additional Information (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Apr. 30, 2016
Line of Credit Facility [Line Items]
Unamortized debt issuance costs	$ 155,009
Revolving Credit Facility | Texas Capital Bank, N.A.
Line of Credit Facility [Line Items]
Unamortized debt issuance costs		$ 179,468
Revolving Credit Facility | Delhi Field | Texas Capital Bank, N.A.
Line of Credit Facility [Line Items]
Deferred legal fees	50,414
Costs incurred for title work related to the Dehli Field	107,196
Line of Credit | Senior Secured Reserve-Based Credit Facility
Line of Credit Facility [Line Items]
Unamortized debt issuance costs		$ 168,972
Debt issuance costs amortized	$ 46,374

Restructuring - Investments in

Restructuring - Investments in Well Lift Inc (Details)	1 Months Ended	3 Months Ended		6 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Jun. 30, 2015USD ($)employee	Dec. 31, 2015USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Nov. 01, 2013USD ($)
Schedule of Cost-method Investments [Line Items]
Investment in Well Lift Inc., at cost			$ 0		$ 108,750	$ 0
Restructuring charges		$ 1,300,000			1,257,433	(5,431)	$ 1,293,186
Stock-based compensation					1,750,209	$ 943,653	$ 1,352,322
Restructuring Reserve								$ 1,332,186
GARP
Schedule of Cost-method Investments [Line Items]
Number of employees terminated | employee			3
Restructuring charges				$ 688,205
Restructuring Reserve	$ 628,866	628,866		628,866	$ 419,488
GARP | Restructuring Charges
Schedule of Cost-method Investments [Line Items]
Stock-based compensation				59,339
Well Lift Inc.
Schedule of Cost-method Investments [Line Items]
Investment in Well Lift Inc., at cost	$ 108,750	$ 108,750		$ 108,750
Ownership percentage	17.50%	17.50%		17.50%
Ownership percentage after conversion of preferred stock into common stock	42.50%	42.50%		42.50%
Perpetual royalty percentage	5.00%
Discounted net present value of assets	$ 108,512	$ 108,512		$ 108,512
Well Lift Inc. | GARP | Exchange of Assets
Schedule of Cost-method Investments [Line Items]
Amortization expense	469,395
Inventory write down to production costs	92,901
Depreciation expense	6,932
Total impairments	$ 569,228

Restructuring - Schedule of Res

Restructuring - Schedule of Restructuring and Related Costs (Details) - USD ($)	6 Months Ended	18 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Salary expense
Restructuring Reserve [Roll Forward]
Beginning balance		$ 615,721
Payments		(615,721)
Adjustment to Cost		0
Ending balance		0
Incentive compensation costs
Restructuring Reserve [Roll Forward]
Beginning balance		185,525
Payments		(185,525)
Adjustment to Cost		0
Ending balance		0
Payroll taxes and benefits expense
Restructuring Reserve [Roll Forward]
Beginning balance		154,575
Payments		(110,144)
Adjustment to Cost		(44,431)
Ending balance		0
Accrued liability for restructuring costs
Restructuring Reserve [Roll Forward]
Beginning balance		955,821
Payments		(911,390)
Adjustment to Cost		(44,431)
Ending balance		$ 0
GARP
Restructuring Reserve [Roll Forward]
Beginning balance	$ 628,866
Payments	(209,378)
Adjustment to Cost	0
Ending balance	419,488
GARP | Salary expense
Restructuring Reserve [Roll Forward]
Beginning balance	530,387
Payments	(176,796)
Adjustment to Cost	0
Ending balance	353,591
GARP | Payroll taxes and benefits expense
Restructuring Reserve [Roll Forward]
Beginning balance	98,479
Payments	(32,582)
Adjustment to Cost	0
Ending balance	$ 65,897

Restructuring - Narrative (Deta

Restructuring - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2014	Jun. 30, 2014	Jun. 30, 2015	Dec. 31, 2013	Nov. 01, 2013
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve						$ 1,332,186
Accrued liability for restructuring costs
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve		$ 955,821		$ 0	$ 955,821
Restructuring Charges
Restructuring Cost and Reserve [Line Items]
Non-cash stock-based compensation expense	$ 0		$ 376,365
Restructuring Charges | Stock Compensation, Restructuring
Restructuring Cost and Reserve [Line Items]
Non-cash stock-based compensation expense		$ 376,365

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Other Current Liabilities (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015
Other Liabilities Disclosure [Abstract]
Accrued incentive and other compensation	$ 999,172	$ 578,910
Accrued restructuring charges	419,488	0
Asset retirement obligations due within one year	201,896	57,223
Accrued royalties, including suspended accounts	49,580	75,164
Accrued franchise taxes	62,834	94,885
Payable for settled derivatives	318,708	0
Accrued - other	46,273	49,191
Accrued liabilities and other	$ 2,097,951	$ 855,373

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Asset Retirement Obligations (Details) - USD ($)		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Reconciliation of the beginning and ending asset retirement obligation
Asset retirement obligations—beginning of period		$ 772,990	$ 352,215
Liabilities incurred	[1]	28,505	564,019
Liabilities settled		0	(137,604)
Liabilities sold		0	(52,526)
Accretion of discount		49,054	34,866	$ 41,626
Revisions to previous estimates		111,647	12,020
Asset retirement obligations—ending of period		962,196	772,990	$ 352,215
Less: current asset retirement obligations		(201,896)	(57,223)
Long-term portion of asset retirement obligations		$ 760,300	$ 715,767
[1]	Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest.

Stockholders' Equity - Narrativ

Stockholders' Equity - Narrative (Details) - USD ($)	1 Months Ended		3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2013	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	May 12, 2015
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Common shares issued during period for share based compensation (shares)						1,568,832
Proceeds from the exercise of stock options				$ 51,000	$ 141,600	$ 3,252,801
Stock issued, nonqualified stock options and incentive warrants noncash (shares)						2,635,696
Shares received in lieu of cash payment (shares)						50,956
Shares received in lieu of cash payment, average cost of shares (in USD per share)						$ 12.14
Treasury stock retired (shares)						801,889
Treasury stock retired, value						$ 1,019,840
Purchases of treasury stock (shares)						186,714
Treasury stock acquired, average cost (in USD per share)						$ 12.18
Purchases of treasury stock				1,263,402	504,124	$ 2,273,857
Cash dividends paid (per common share)		$ 0.10	$ 0.05
Dividends paid				6,565,823	9,833,642	9,723,833
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Cash dividends to preferred stockholders				$ 674,302	$ 674,302	674,302
Series A Cumulative Preferred Stock
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Issuance of preferred stock (in shares)				317,319
Preferred stock dividend rate (as a percent)				8.50%	8.50%
Amount of sinking fund available to stockholders				$ 0
Preferred stock, liquidation preference (in dollars per share)	$ 25			$ 25	$ 25
Dividend payable monthly on preferred stock (in dollars per share)				$ 0.177083
Cash dividends to preferred stockholders				$ 674,302	$ 674,302	$ 674,302
Common Stock
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Purchases of treasury stock (shares)				218,682	70,907	186,714
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Percentage of cash dividends treated as qualified dividend income					14.00%
Percentage of cash dividends treated as return of capital					86.00%
Preferred
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Percentage of cash dividends treated as qualified dividend income					100.00%
2015 Share Repurchase Program | Common Stock
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Purchases of treasury stock (shares)	265,762			202,390
Treasury stock acquired, average cost (in USD per share)	$ 6.05			$ 5.80
Purchases of treasury stock	$ 1,609,008			$ 1,173,899
Amount authorized to be repurchased							$ 5,000,000

Stock-Based Incentive Plan - Na

Stock-Based Incentive Plan - Narrative (Details) - USD ($)	Aug. 27, 2014	Feb. 29, 2016	Dec. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise of stock options (shares)				50,000	87,000
Stock options intrinsic value				$ 131,000	$ 501,810
Option vested (in shares)				35,231
Restructuring Charges
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash stock-based compensation expense				$ 0		$ 376,365
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vested (in shares)				0	0	0
Stock Options and Incentive Warrants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise of stock options (shares)						4,644,759
Stock options intrinsic value						$ 47,504,114
Contingent Restricted Stock Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares forfeited (shares)			14,212	29,866
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares forfeited (shares)			31,467	62,774
Restricted stock, vested (shares)				86,719	91,306	277,198
Restricted stock, vested in period, grant date fair value (in dollars per share)				$ 757,229	$ 766,970	$ 1,796,243
Non-cash stock-based compensation expense				$ 1,809,548	$ 943,653	$ 1,728,687
Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)				3 years 303 days
Fair value at grant date, per share (in dollars per share)				$ 4.58
Shares granted (in shares)				64,752
Restricted Stock, Market Based | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)					3 years 109 days
Fair value at grant date, per share (in dollars per share)				$ 2.93	$ 4.26
Restricted Stock, Market Based | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)					2 years 200 days
Fair value at grant date, per share (in dollars per share)				5.07	$ 8.40
Restricted Stock, Performance Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at grant date, per share (in dollars per share)				$ 6.09
Shares granted (in shares)				64,752
Restricted Stock, Performance Based | Various Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares voluntarily relinquished (in shares)		31,307
Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at grant date, per share (in dollars per share)				$ 5.84
Shares granted (in shares)				164,610
Restricted Stock, Service Based | Various Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)		22,016
Contingent Performance-based Shares | Various Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares voluntarily relinquished (in shares)		15,654
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for granting (shares)				6,500,000
Shares available for grant (shares)				282,133
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | Restricted Stock and Contingent Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period (in years)				4 years
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	4 years
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)				4 years

Stock-Based Incentive Plan - Sc

Stock-Based Incentive Plan - Schedule of Options and Incentive Warrants (Details) - USD ($)		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015
Number of Stock Options
Stock Options Outstanding, Beginning of Period (in shares)		91,061
Stock Options , Exercises (in shares)		(50,000)	(87,000)
Stock Options, Expirations (in shares)		(5,830)
Stock Options Outstanding, End of Period (in shares)		35,231	91,061
Stock Options, Vested and Expected to Vest (in shares)		35,231
Stock Options, Exercisable (in shares)		35,231
Weighted Average Exercise Price
Stock Options Outstanding, Weighted Average Exercise Price, Beginning of Period (in USD per share)		$ 2.50
Stock Options, Exercises, Weighted Average Exercise Price (in USD per share)		2.55
Stock Options, Expirations, Weighted Average Exercise Price (in USD per share)		4.02
Stock Options, Weighted Average Exercise Price, End of Period (in USD per share)		2.19	$ 2.50
Stock Options, Vested and Expected to Vest, Weighted Average Exercise Price (in USD per share)		2.19
Stock Options, Exercisable, Weighted Average Exercise Price (in USD per share)		$ 2.19
Aggregate Intrinsic Value
Stock Options, Outstanding, Aggregate Intrinsic Value	[1]	$ 115,558
Stock Options, Vested and Expected to Vest, Aggregate Intrinsic Value	[1]	115,558
Stock Options, Exercisable, Aggregate Intrinsic Value	[1]	$ 115,558
Stock Options, Outstanding, Weighted Average Remaining Contractual Term (in years)		1 year 2 months 12 days
Stock Options, Vested and Expected to Vest, Weighted Average Remaining Contractual Term (in years)		1 year 2 months 12 days
Stock Options, Exercisable, Weighted Average Remaining Contractual Term (in years)		1 year 2 months 12 days
Common Stock
Aggregate Intrinsic Value
Share price (in dollars per share)		$ 5.47
[1]	Based upon the difference between the market price of our common stock on the last trading date of the period ($5.47 as of June 30, 2016) and the Stock Option exercise price of in-the-money Stock Options.

Stock-Based Incentive Plan - 66

Stock-Based Incentive Plan - Schedule of Restricted Stock (Details) - USD ($)	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Restricted Stock
Number of Restricted Shares
Nonvested, beginning of period (shares)		262,227
Vested (shares)		(86,719)	(91,306)	(277,198)
Forfeited (shares)	(31,467)	(62,774)
Nonvested, end of period (shares)		406,848	262,227
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, beginning of period (in USD per share)		$ 9.37
Vested, weighted average grant date fair value (in USD per share)		8.73
Forfeited, weighted average grant date fair value (in USD per share)		9.72
Weighted average grant date fair value, end of period (in USD per share)		$ 6.74	$ 9.37
Unamortized compensation expense		$ 1,536,125	$ 0
Weighted Average Remaining Amortization Period (in years)		2 years 7 months 6 days
Restricted Stock, Service Based
Number of Restricted Shares
Grants (shares)		164,610
Nonvested, end of period (shares)		224,515
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)		$ 5.84
Weighted average grant date fair value, end of period (in USD per share)		$ 7.08
Restricted Stock, Performance Based
Number of Restricted Shares
Grants (shares)		64,752
Nonvested, end of period (shares)		89,079
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)		$ 6.09
Weighted average grant date fair value, end of period (in USD per share)		$ 7.17
Restricted Stock, Market Based
Number of Restricted Shares
Grants (shares)		64,752
Nonvested, end of period (shares)		93,254
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)		$ 4.58
Weighted average grant date fair value, end of period (in USD per share)		$ 5.50

Stock-Based Incentive Plan - 67

Stock-Based Incentive Plan - Schedule of Contingent Restricted Stock (Details) - USD ($)		1 Months Ended	12 Months Ended
		Dec. 31, 2015	Jun. 30, 2016
Contingent Restricted Stock Grants
Number of Restricted Stock Units
Nonvested, beginning of period (shares)			56,286
Forfeited (shares)		(14,212)	(29,866)
Nonvested, end of period (shares)			91,172
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, beginning of period (in USD per share)			$ 8.20
Forfeited, weighted average grant date fair value (in USD per share)			9.33
Weighted average grant date fair value, end of period (in USD per share)			$ 5.21
Unamortized compensation expense	[1]		$ 107,219
Weighted Average Remaining Amortization Period (in years)			2 years 9 months 18 days
Contingent Restricted Stock, Performance Based
Number of Restricted Stock Units
Grants (shares)			32,376
Nonvested, end of period (shares)			44,542
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)			$ 6.09
Weighted average grant date fair value, end of period (in USD per share)			$ 7.17
Potential future compensation expense			$ 122,268
Contingent Restricted Stock, Market Based
Number of Restricted Stock Units
Grants (shares)			32,376
Nonvested, end of period (shares)			46,630
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)			$ 2.93
Weighted average grant date fair value, end of period (in USD per share)			$ 3.34
[1]	Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Supplemental Disclosure of Ca68

Supplemental Disclosure of Cash Flow Information - Schedule of Supplement Cash Flow (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Supplemental Cash Flow Elements [Abstract]
Income taxes paid	$ 540,000	$ 220,000	$ 755,941
Income tax refunds	1,556,999	331,733	0
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	(2,250,048)	5,422,566	(183,766)
Deferred loan costs charged to oil and gas property costs	107,196	0	0
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	140,151	576,039	66,976
Mengel working interest acquired in Delhi Field litigation settlement	596,500	0	0
Royalty rights acquired through non-monetary exchange of patent and trademark assets	108,512	0	0
Previously acquired Company shares swapped by holders to pay stock option exercise price	76,500	0	618,606
Accrued purchases of treasury stock	$ (170,283)	$ 170,283	$ 0

Income Taxes - Narrative (Detai

Income Taxes - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended
	Sep. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Operating Loss Carryforwards [Line Items]
Unrecognized tax benefits		$ 0	$ 0	$ 0
Statutory tax rate		34.00%
Tax loss carryforwards from exercise of options and warrants		$ 25,300,000
Tax benefits related to stock-based compensation		9,650,657	$ 1,633,946	$ 509,096
Net loss for state tax purposes	$ 19,100,000
Mineral Property Depletion
Operating Loss Carryforwards [Line Items]
Depletion carryforward		5,000,000
Federal
Operating Loss Carryforwards [Line Items]
Tax loss carryforward from reverse merger		1,200,000
Carryforward from reverse merger		300,000
Annual amount of carryforward from reverse merger through 2023		$ 39,648
State
Operating Loss Carryforwards [Line Items]
Net loss for state tax purposes	24,200,000
Louisiana | State
Operating Loss Carryforwards [Line Items]
Income tax refund	1,500,000
Interest on refund recorded as a deduction of current income tax expense	$ 57,467

Income Taxes - Components of In

Income Taxes - Components of Income Tax Provision (Benefit) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Current:
Federal	$ 8,731,290	$ 1,413,296	$ 386,018
State	264,254	608,436	161,168
Total current income tax provision	8,995,544	2,021,732	547,186
Deferred:
Federal	541,891	1,282,059	1,319,727
State	33,344	140,430	25,085
Total deferred income tax provision	575,235	1,422,489	1,344,812
Total income tax provision	$ 9,570,779	$ 3,444,221	$ 1,891,998

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Statutory and Income Tax Expense (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Income Tax Disclosure [Abstract]
Income tax provision (benefit) computed at the statutory federal rate	$ 11,638,588	$ 2,868,267	$ 1,866,366
Depletion in excess of basis	(2,242,620)	0	0
State income taxes, net of federal tax benefit	196,415	595,708	189,081
Permanent differences related to stock-based compensation	0	0	(155,817)
Other permanent differences	(21,604)	(19,754)	(7,632)
Total income tax provision	$ 9,570,779	$ 3,444,221	$ 1,891,998

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Income Taxes (Details) - USD ($)		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Deferred tax assets:
Non-qualified stock-based compensation		$ 553,182	$ 173,647	$ 134,469
Net operating loss carry-forwards		386,808	400,288	427,249
AMT credit carry-forward	[1]	0	701,254	701,254
Other		130,947	91,113	165,775
Gross deferred tax assets		1,070,937	1,366,302	1,428,747
Valuation allowance		(292,446)	(292,446)	(292,446)
Total deferred tax assets		778,491	1,073,856	1,136,301
Deferred tax liability:
Oil and natural gas properties		(12,513,863)	(12,233,993)	(10,873,949)
Total deferred tax liability		(12,513,863)	(12,233,993)	(10,873,949)
Net deferred tax liability		(11,735,372)	$ (11,160,137)	$ (9,737,648)
AMT credit carry-forward		901,545
AMT associated with stock-based compensation		$ 200,291
[1]	In fiscal 2016 we used our total AMT credit carry-forward of $901,545. Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation.

Income Taxes - Balance Sheet It

Income Taxes - Balance Sheet Items (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Income Tax Disclosure [Abstract]
Current deferred tax asset	$ 105,321	$ 82,414	$ 159,624
Non-current deferred tax liability	11,840,693	11,242,551	9,897,272
Net liability	$ 11,735,372	$ 11,160,137	$ 9,737,648

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Vice President
Related Party Transaction [Line Items]
Related party payments	$ 0	$ 26,579	$ 10,113

Net Income Per Share - Schedule

Net Income Per Share - Schedule of Basic and Diluted Earnings (Loss) Per Share (Details) - USD ($)	3 Months Ended											12 Months Ended
	Jun. 30, 2016	[1]	Mar. 31, 2016	Dec. 31, 2015	[2]	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	[3]	Sep. 30, 2014	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Numerator
Net income attributable to common shareholders	$ 20,705,894		$ (298,183)	$ 654,697		$ 2,923,652	$ 1,719,767	$ 566,011	$ 1,071,342		$ 960,435	$ 23,986,060	$ 4,317,555	$ 2,923,011
Denominator
Weighted average number of common shares—Basic (in shares)												32,810,375	32,817,456	30,895,832
Effect of dilutive securities:
Total weighted average dilutive securities (in shares)												50,856	106,562	1,668,235
Weighted average number of common shares and dilutive potential common shares used in diluted EPS (in shares)												32,861,231	32,924,018	32,564,067
Net income (loss) per common share - Basic (in dollars per share)	$ 0.63		$ (0.01)	$ 0.02		$ 0.09	$ 0.05	$ 0.02	$ 0.03		$ 0.03	$ 0.73	$ 0.13	$ 0.09
Net income (loss) per common share - Diluted (in dollars per share)	$ 0.63		$ (0.01)	$ 0.02		$ 0.09	$ 0.05	$ 0.02	$ 0.03		$ 0.03	$ 0.73	$ 0.13	$ 0.09
Contingent restricted stock grants
Effect of dilutive securities:
Weighted average dilutive securities (in shares)												9,378	4,422	0
Stock Options
Effect of dilutive securities:
Weighted average dilutive securities (in shares)												41,478	102,140	1,668,235
[1]	Includes gain on settlement of Delhi field litigation of $28.1 million.
[2]	Includes $1.3 million restructuring charge.
[3]	Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field.

Net Income Per Share - Schedu76

Net Income Per Share - Schedule of Outstanding Potentially Dilutive Securities (Details) - $ / shares	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Exercise Price (in dollars per share)	$ 0.61	$ 1.55
Outstanding (in shares)	126,403	147,347
Contingent Restricted Stock grants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Exercise Price (in dollars per share)	$ 0	$ 0
Outstanding (in shares)	91,172	56,286
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Exercise Price (in dollars per share)	$ 2.19	$ 2.50	$ 2.08
Outstanding (in shares)	35,231	91,061	178,061

Credit Agreements (Details)

Credit Agreements (Details)	Apr. 11, 2016USD ($)	Feb. 29, 2012USD ($)	Jun. 30, 2016USD ($)	Apr. 30, 2016USD ($)	Jun. 30, 2015USD ($)
Debt Instrument [Line Items]
Unamortized debt issuance costs			$ 155,009
Texas Capital Bank, N.A. | Revolving Credit Facility
Debt Instrument [Line Items]
Term of debt instrument		4 years
Debt issuance costs		$ 179,468
Unamortized debt issuance costs				$ 179,468
Current borrowing base		$ 5,000,000
Outstanding borrowings					$ 0
Texas Capital Bank, N.A. | Letter of Credit
Debt Instrument [Line Items]
Outstanding borrowings					$ 0
Line of Credit | Senior Secured Reserve-Based Credit Facility | Revolving Credit Facility
Debt Instrument [Line Items]
Term of debt instrument	3 years
Maximum borrowing capacity	$ 50,000,000
Initial borrowing base	$ 10,000,000
Placement fee percentage	0.50%
Placement fee amount	$ 50,000
Commitment fee percentage	0.25%
Maximum total leverage ratio	3
Debt service coverage ratio	1.10
Minimum consolidated tangible net worth	$ 40,000,000
Debt issuance costs	$ 168,972
Line of Credit | Senior Secured Reserve-Based Credit Facility | LIBOR | Revolving Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate	2.75%
Line of Credit | Senior Secured Reserve-Based Credit Facility | Prime Rate | Revolving Credit Facility
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%

Commitments and Contingencies -

Commitments and Contingencies - Schedule of Future Minimum Lease Commitments (Details)	Jun. 30, 2016USD ($)
Commitments and Contingencies Disclosure [Abstract]
2,017	$ 80,235
2,018	73,073
2,019	66,984
Total	$ 220,292

Commitments and Contingencies79

Commitments and Contingencies - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Commitments and Contingencies Disclosure [Abstract]
Term of operating lease (in years)	3 years
Rent expense	$ 182,626	$ 175,103	$ 174,229

Concentrations of Credit Risk -

Concentrations of Credit Risk - Schedule of Credit Risk (Details) - Net revenue - Major Customers	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Concentrations of Credit Risk
Percent of Total Revenue	100.00%	100.00%	100.00%
Plains Marketing L.P. (includes Delhi production)
Concentrations of Credit Risk
Percent of Total Revenue	99.00%	99.00%	96.00%
Enterprise Crude Oil LLC
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	0.00%	2.00%
Flint Hills
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	0.00%	1.00%
ETC Texas Pipeline, LTD.
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	0.00%	1.00%
All others
Concentrations of Credit Risk
Percent of Total Revenue	1.00%	1.00%	0.00%

Retirement Plan (Details)

Retirement Plan (Details) - USD ($)	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Compensation and Retirement Disclosure [Abstract]
Employer match of employee contributions of first 6% of eligible compensation (as a percent)	100.00%
Percentage of eligible compensation, matched 100% by employer	6.00%
Matching contribution to the plan	$ 88,348	$ 85,676	$ 116,873

Derivatives (Details)

Derivatives (Details)	12 Months Ended
	Jun. 30, 2016USD ($)$ / bblbbl	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)
Derivative [Line Items]
Net asset position of derivatives with counterparty	$ 14,132
Gain on derivatives	3,439,229
Gain on settled derivatives	3,315,123
Net gain on unsettled derivatives	124,106
(Gain) loss on derivative instruments, net	$ (3,439,229)	$ 109,974	$ 0
Crude Oil | Options
Derivative [Line Items]
Volumes (in Bbls./day) | bbl	600
Weighted Average Floor Price ($ per Bbl) | $ / bbl	45
Weighted Average Ceiling Price ($ per Bbl) | $ / bbl	55
Weighted Average Put Spread ($ per Bbl) | $ / bbl	10

Fair Value Measurement - Assets

Fair Value Measurement - Assets and Liabilities Measured on Recurring Basis (Details) - Level 2	Jun. 30, 2016USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Current derivative assets, Gross Amounts Recognized	$ 45,263
Current derivative assets, Gross Amounts Offset in the Consolidated Balance Sheet	(31,131)
Current derivative assets, Net Amounts Presented in the Consolidated Balance Sheets	14,132
Current derivative liabilities, Gross Amounts Recognized	(31,131)
Current derivative liabilities, Gross Amounts Offset in the Consolidated Balance Sheet	31,131
Current derivative liabilities, Net Amounts Presented in the Consolidated Balance Sheets	0
Total, Gross Amounts Recognized	14,132
Total, Gross Amounts Offset in the Consolidated Balance Sheet	0
Total, Net Amounts Presented in the Consolidated Balance Sheets	$ 14,132

Supplemental Disclosures abou84

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of Costs Incurred and Capitalized in Oil and Natural Gas Property Acquisition, Exploration, and Development (Details) - USD ($)		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Property acquisition costs:
Proved property		$ 0	$ 0	$ 0
Unproved property	[1]	596,500	0	47,344
Exploration costs		0	0	757,423
Development costs		19,093,200	10,975,637	18,566
Total costs incurred for oil and natural gas activities		$ 19,689,700	$ 10,975,637	$ 823,333
[1]	As described in Note 3 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500. This cost is included in properties subject to amortization.

Supplemental Disclosures abou85

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Estimated Quantities of Proved Oil and Natural Gas Reserves (Details)	12 Months Ended
	Jun. 30, 2016BoeMcfbbl		Jun. 30, 2015BoeMcfbbl		Jun. 30, 2014BoeMcfbbl		Jun. 30, 2013BoeMcfbbl
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in BOE) | Boe	12,446,394		13,289,510		13,766,440
Revisions of previous estimates (in BOE) | Boe	(964,171)	[1]	(390,330)	[2]	(247,350)	[3]
Improved recovery, extensions and discoveries (in BOE) | Boe	0		0		132,884
Sales of minerals in place (in BOE) | Boe	0		0		(184,722)
Production (sales volumes) (in BOE) | Boe	(658,802)		(452,786)		(177,742)
Balance at the end of the period (in BOE) | Boe	10,823,421		12,446,394		13,289,510
Proved developed reserves (in BOE) | Boe	7,168,249		7,349,626		7,970,562		10,089,861
Proved undeveloped reserves (in BOE) | Boe	3,655,172		5,096,768		5,318,948		3,676,579
Delhi Field
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Revisions of previous estimates (in BOE) | Boe					1,679,481
Crude Oil
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in Bbls/Mcf)	10,011,976		10,526,344		12,782,755
Revisions of previous estimates (in Bbls/Mcf)	(765,385)	[1]	(64,074)	[2]	(1,919,052)	[3]
Improved recovery, extensions and discoveries (in Bbls/Mcf)	0		0		17,146
Sales of minerals in place (in Bbls/Mcf)	0		0		(184,722)
Production (sales volumes) (in Bbls/Mcf)	(658,041)		(450,294)		(169,783)
Balance at the end of the period (in Bbls/Mcf)	8,588,550		10,011,976		10,526,344
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Proved developed reserves (in Bbls/Mcf)	7,168,249		7,347,231		7,858,224		10,077,522
Proved undeveloped reserves (in Bbls/Mcf)	1,420,301		2,664,745		2,668,120		2,705,233
Crude Oil | Delhi Field
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Revisions of previous estimates (in Bbls/Mcf)					1,817,224
Natural Gas Liquids
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in Bbls/Mcf)	2,433,595		2,278,688		979,885
Revisions of previous estimates (in Bbls/Mcf)	(198,233)	[1]	156,195	[2]	1,269,588	[3]
Improved recovery, extensions and discoveries (in Bbls/Mcf)	0		0		32,731
Sales of minerals in place (in Bbls/Mcf)	0		0		0
Production (sales volumes) (in Bbls/Mcf)	(491)		(1,288)		(3,516)
Balance at the end of the period (in Bbls/Mcf)	2,234,871		2,433,595		2,278,688
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Proved developed reserves (in Bbls/Mcf)	0		1,572		32,164		8,539
Proved undeveloped reserves (in Bbls/Mcf)	2,234,871		2,432,023		2,246,524		971,346
Natural Gas Liquids | Giddings Field
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Revisions of previous estimates (in Bbls/Mcf)			(29,304)
Natural Gas
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Balance at the beginning of the period (in Bbls/Mcf) | Mcf	4,939		2,906,863		22,797
Revisions of previous estimates (in Bbls/Mcf) | Mcf	(3,319)	[1]	(2,894,703)	[2]	2,412,677	[3]
Improved recovery, extensions and discoveries (in Bbls/Mcf) | Mcf	0		0		498,044
Sales of minerals in place (in Bbls/Mcf) | Mcf	0		0		0
Production (sales volumes) (in Bbls/Mcf) | Mcf	(1,620)		(7,221)		(26,655)
Balance at the end of the period (in Bbls/Mcf) | Mcf	0		4,939		2,906,863
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Proved developed reserves (in Bbls/Mcf) | Mcf	0		4,939		481,042		22,797
Proved undeveloped reserves (in Bbls/Mcf) | Mcf	0		0		2,425,821		0
Natural Gas | Delhi Field
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Revisions of previous estimates (in Bbls/Mcf) | Mcf			(2,246,524)
Natural Gas | Giddings Field
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves
Revisions of previous estimates (in Bbls/Mcf) | Mcf			(452,786)
[1]	The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period.
[2]	The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well.
[3]	Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes.

Supplemental Disclosures abou86

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserves (Details) - USD ($)	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Standardized measure of discounted future net cash flows
Future cash inflows	$ 383,491,193	$ 807,030,282	$ 1,193,515,075
Future production costs and severance taxes	(179,182,565)	(309,225,333)	(475,387,931)
Future development costs	(16,595,047)	(49,691,006)	(46,154,178)
Future income tax expenses	(45,713,438)	(123,888,665)	(195,581,510)
Future net cash flows	142,000,143	324,225,278	476,391,456
10% annual discount for estimated timing of cash flows	(64,042,824)	(165,028,739)	(250,313,784)
Standardized measure of discounted future net cash flows	$ 77,957,319	$ 159,196,539	$ 226,077,672	$ 307,220,699

Supplemental Disclosures abou87

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of NYMEX Prices Used in Determining Future Cash Flows (Details)	12 Months Ended
	Jun. 30, 2016$ / bbl$ / MMBtu	Jun. 30, 2015$ / bbl$ / MMBtu	Jun. 30, 2014$ / bbl$ / MMBtu
Oil (per barrel)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices Used in Determining Future Cash Flows | $ / bbl	42.91	71.88	100.37
Gas (per million BTU)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices Used in Determining Future Cash Flows | $ / MMBtu	0	3.44	4.10

Supplemental Disclosures abou88

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Roll Forward of Changes in Standardized Measure of Discount Future Cash Flows on Proved Crude Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) - USD ($)		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves
Balance, beginning of year		$ 159,196,539	$ 226,077,672	$ 307,220,699
Net changes in sales prices and production costs related to future production		(120,832,747)	(88,043,095)	(73,439,526)
Changes in estimated future development costs		74,991	(9,585,405)	9,848,614
Sales of oil and gas produced during the period, net of production costs		(17,079,363)	(18,538,016)	(16,479,934)
Net change due to extensions, discoveries, and improved recovery		0	0	775,574
Net change due to revisions in quantity estimates		(18,821,014)	(9,391,321)	(23,757,788)
Net change due to sales of minerals in place		0	0	(3,150,277)
Development costs incurred during the period		16,327,883	7,785,095	0
Accretion of discount		21,870,650	31,974,540	45,896,187
Net change in discounted income taxes		36,598,239	34,157,767	58,073,450
Net changes in timing of production and other	[1]	622,141	(15,240,698)	(78,909,327)
Balance, end of year		$ 77,957,319	$ 159,196,539	$ 226,077,672
[1]	Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014.

Supplemental Disclosures abou89

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Narrative (Details)	Jun. 24, 2016USD ($)	Jun. 30, 2016USD ($)BoeMcfbbl		Jun. 30, 2015USD ($)BoeMcfbbl		Jun. 30, 2014USD ($)BoeMcfbbl
Reserve Quantities [Line Items]
Oil and natural gas property costs attributable to the recognition of asset retirement obligations | $		$ 140,151		$ 576,039		$ 66,976
Fair value of litigation settlement | $		$ 596,500		$ 0		$ 0
Period Considered for Unweighted Arithmetic Average for Determining Reserve Volumes and Values		12 months
Positive revision of previous estimate (in BOE) | Boe		(964,171)	[1]	(390,330)	[2]	(247,350)	[3]
Period Considered for Determining Unweighted Arithmetic Average of First Day of Month, Commodity Prices		12 months
Crude Oil
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf)		(765,385)	[1]	(64,074)	[2]	(1,919,052)	[3]
Natural Gas Liquids
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf)		(198,233)	[1]	156,195	[2]	1,269,588	[3]
Revision due to improved design (in Bbls/Mcf)				185,499
Natural Gas
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf		(3,319)	[1]	(2,894,703)	[2]	2,412,677	[3]
Delhi Field
Reserve Quantities [Line Items]
Positive revision of previous estimate (in BOE) | Boe						1,679,481
Delhi Field | Crude Oil
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf)						1,817,224
Delhi Field | Natural Gas Liquids
Reserve Quantities [Line Items]
Revision due to improved design (in Bbls/Mcf)						1,275,178
Delhi Field | Natural Gas
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf				(2,246,524)
Revision due to improved design (in Bbls/Mcf) | Mcf						2,425,821
Giddings Field | Natural Gas Liquids
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf)				(29,304)
Giddings Field | Natural Gas
Reserve Quantities [Line Items]
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf				(452,786)
Dehli Field Litigation | Denbury Resources, Inc
Reserve Quantities [Line Items]
Working interest in Mengal Sand Interval	23.90%
Fair value of litigation settlement | $	$ 596,500
[1]	The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period.
[2]	The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well.
[3]	Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes.

Selected Quarterly Financial 90

Selected Quarterly Financial Data (Unaudited) - Summary of Quarterly Financial Information (Details) - USD ($)	3 Months Ended											12 Months Ended
	Jun. 30, 2016	[1]	Mar. 31, 2016	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2014
Revenues	$ 7,240,434		$ 5,106,735	$ 6,622,927	[2]	$ 7,379,406	$ 9,063,682	$ 7,064,689	$ 7,708,067	[3]	$ 4,004,827	$ 26,349,502	$ 27,841,265	$ 17,673,508
Operating income (loss)	954,823		(681,147)	(454,987)	[2]	1,846,498	3,334,547	1,245,990	2,162,294	[3]	1,840,866	1,665,187	8,583,697	5,528,147
Net income (loss) available to common shareholders	$ 20,705,894		$ (298,183)	$ 654,697	[2]	$ 2,923,652	$ 1,719,767	$ 566,011	$ 1,071,342	[3]	$ 960,435	$ 23,986,060	$ 4,317,555	$ 2,923,011
Basic net income (loss) per share (in dollars per share)	$ 0.63		$ (0.01)	$ 0.02	[2]	$ 0.09	$ 0.05	$ 0.02	$ 0.03	[3]	$ 0.03	$ 0.73	$ 0.13	$ 0.09
Diluted net income (loss) per share (in dollars per share)	$ 0.63		$ (0.01)	$ 0.02	[2]	$ 0.09	$ 0.05	$ 0.02	$ 0.03	[3]	$ 0.03	$ 0.73	$ 0.13	$ 0.09
Restructuring charges				$ 1,300,000								$ 1,257,433	$ (5,431)	$ 1,293,186
Delhi field litigation settlement gain												28,096,500	$ 0	$ 0
Delhi Field
Working interest									23.90%
Net revenue interest									19.00%
Dehli Field Litigation
Delhi field litigation settlement gain												$ 28,100,000
[1]	Includes gain on settlement of Delhi field litigation of $28.1 million.
[2]	Includes $1.3 million restructuring charge.
[3]	Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field.