View Filing Data

Depreciation, depletion and amortization

$ 34,484,896

$ 26,349,502

$ 27,841,265

Operating costs

Production costs

10,835,809

9,062,179

9,335,244

5,719,405

5,165,120

3,615,737

Accretion of discount on asset retirement obligations

59,664

49,054

34,866

General and administrative expenses

^[1]

4,985,408

9,079,597

6,256,783

Restructuring charges (income)

4,488

1,257,433

(5,431)

Total operating costs

21,604,774

24,684,315

19,257,568

Income from operations

12,880,122

1,665,187

8,583,697

Other

Gain on realized derivative instruments, net

43,890

3,315,123

Gain (loss) on unrealized derivative instruments, net

(14,132)

124,106

(109,974)

Delhi field litigation settlement

28,096,500

Delhi field insurance recovery related to pre-reversion event

1,074,957

Interest and other income

56,855

26,211

35,991

Interest expense

(81,758)

(70,943)

(73,636)

Income before income tax provision

12,884,977

34,231,141

8,436,078

Income tax provision

4,840,664

9,570,779

3,444,221

Net income attributable to the Company

8,044,313

24,660,362

4,991,857

Dividends on preferred stock

250,990

674,302

Deemed dividend on preferred shares called for redemption

1,002,440

Net income attributable to common shareholders

$ 6,790,883

$ 23,986,060

$ 4,317,555

Earnings per common share

Basic (in dollars per share)

$ 0.21

$ 0.73

$ 0.13

Diluted (in dollars per share)

$ 0.21

$ 0.73

$ 0.13

Weighted average number of common shares outstanding

Basic (in shares)

33,034,480

32,810,375

32,817,456

Diluted (in shares)

33,110,560

32,861,231

32,924,018

Crude Oil

Revenues

$ 33,550,698

$ 26,130,762

$ 27,761,291

Natural Gas Liquids

Revenues

934,202

7,885

37,227

Natural Gas

Revenues

Artificial Lift Technology

(4)

2,895

26,601

Revenues

207,960

16,146

Operating costs

Production costs

$ 0

$ 70,932

$ 20,369

[1]	General and administrative expenses for the years ended June 30, 2017, 2016 and 2015 included non-cash stock-based compensation expense of $1,180,618, $1,750,209, and $943,653, respectively. These years also included litigation expenses of $127,435, $2,729,755, and $1,015,105, respectively.

Consolidated Statements of Operations (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Non-cash stock-based compensation expense	$ 1,180,618	$ 1,809,548	$ 943,653
General and Administrative Expense
Non-cash stock-based compensation expense	1,180,618	1,750,209	943,653
Litigation expense	$ 127,435	$ 2,729,755	$ 1,015,105

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
Consolidated Statements of Cash Flows - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Cash Flows From Operating Activities
Net income attributable to the Company	$ 8,044,313	$ 24,660,362	$ 4,991,857
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	5,775,946	5,211,494	3,664,373
Impairments included in restructuring charge	0	569,228	0
Stock-based compensation	1,180,618	1,809,548	943,653
Accretion of discount on asset retirement obligations	59,664	49,054	34,866
Settlement of asset retirement obligations	(157,910)	0	(223,564)
Deferred income taxes	4,090,919	575,235	1,422,489
Deferred rent	0	0	(17,145)
(Gain) loss on derivative instruments, net	(29,758)	(3,439,229)	109,974
Noncash gain on Delhi field litigation settlement	0	(596,500)	0
Write-off of deferred loan costs	0	50,414	0
Changes in operating assets and liabilities:
Receivables	(88,514)	484,285	(1,665,261)
Prepaid expenses and other current assets	(135,923)	24,754	378,049
Accounts payable and accrued expenses	(1,626,648)	822,730	551,452
Income taxes payable	(621,850)	431,818	190,032
Net cash provided by operating activities	16,490,857	30,653,193	10,380,775
Cash flows from investing activities
Derivative settlements received (paid)	(272,318)	3,633,831	0
Proceeds from asset sales	0	0	398,242
Capital expenditure for development of oil and natural gas properties	(10,158,960)	(21,095,901)	(4,890,909)
Capital expenditures for technology and other equipment	(32,260)	(6,883)	(313,059)
Other assets	0	(161,345)	(236,559)
Net cash used by investing activities	(10,463,538)	(17,630,298)	(5,042,285)
Cash flows from financing activities
Proceeds from the exercise of stock options	0	51,000	141,600
Common share repurchases, including shares surrendered for tax withholding	(459,858)	(1,357,185)	(333,841)
Cash dividends to common stockholders	(8,432,435)	(6,565,823)	(9,833,642)
Cash dividends to preferred stockholders	(250,990)	(674,302)	(674,302)
Redemption of preferred shares	(7,932,975)	0	0
Deferred loan costs	0	(168,972)	(94,075)
Tax benefits related to stock-based compensation	0	9,650,657	1,633,946
Other	32	33	67
Net cash provided (used) by financing activities	(17,076,226)	935,408	(9,160,247)
Net increase (decrease) in cash and cash equivalents	(11,048,907)	13,958,303	(3,821,757)
Cash and cash equivalents, beginning of year	34,077,060	20,118,757	23,940,514
Cash and cash equivalents, end of year	$ 23,028,153	$ 34,077,060	$ 20,118,757

Consolidated Statements of Changes in Stockholders' Equity - USD ($)	Total	Preferred	Common Stock	Additional Paid-in Capital	Retained Earnings	Treasury Stock
Balance at Jun. 30, 2014	$ 51,877,522	$ 317	$ 32,615	$ 34,632,377	$ 17,212,213	$ 0
Balance (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 (shares)	87,000		87,000
Exercise of stock options	$ 141,600		$ 87	141,513
Common share repurchases, including shares surrendered for tax withholding (shares)			(70,907)
Common share repurchases, including shares surrendered for tax withholding	(504,124)					(504,124)
Retirements of treasury stock	0		$ (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 attributable to the Company	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 (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 (shares)	50,000		50,000
Exercise of stock options	$ 127,500		$ 50	127,450
Common share repurchases, including shares surrendered for tax withholding (shares)			(218,682)
Common share repurchases, including shares surrendered for tax withholding	(1,263,402)					(1,263,402)
Forfeiture of restricted stock	0		$ (41)	41
Forfeiture of restricted stock (shares)			(40,758)
Retirements of treasury stock	0		$ (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 attributable to the Company	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 (shares) at Jun. 30, 2016		317,319	32,907,863
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock	$ 32		$ 228	(196)
Issuance of restricted common stock (shares)			227,889
Exercise of stock options (shares)	35,231		35,231
Exercise of stock options	$ 77,156		$ 35	77,121
Common share repurchases, including shares surrendered for tax withholding (shares)			(83,675)
Common share repurchases, including shares surrendered for tax withholding	(537,014)					(537,014)
Retirements of treasury stock	0		$ (83)	(536,931)		537,014
Stock-based compensation	1,180,618			1,180,618
Redemption of preferred shares (shares)		(317,319)
Redemption of preferred shares	(7,932,975)	$ (317)		(6,930,218)	(1,002,440)
Net income attributable to the Company	8,044,313				8,044,313
Common stock cash dividends	(8,432,435)				(8,432,435)
Preferred stock cash dividends	(250,990)				(250,990)
Balance at Jun. 30, 2017	$ 68,469,855	$ 0	$ 33,087	$ 40,961,957	$ 27,474,811	$ 0
Balance (shares) at Jun. 30, 2017		0	33,087,308

Organization and Basis of Preparation	12 Months Ended
Organization and Basis of Preparation	Jun. 30, 2017
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"), together with 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 and production of oil and gas reserves. 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 7, 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 (a) 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, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets and (f) 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 Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Jun. 30, 2017
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. 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, 2017, 2016 or 2015. 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. These assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which was depreciated using a method which approximated 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. We estimate the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. Service-based and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. Market-based awards are valued using a Monte Carlo simulation based on the historical volatility of the Company's total stock return compared to the historical volatilities of other companies or indices to which we compare our performance. This Monte Carlo simulation also provides an expected vesting period. We use the Black-Scholes option-pricing model to determine grant date fair value of any Stock Option or Incentive Warrant awards. For service-based awards, stock-based compensation is recognized ratably over the service period. For performance-based awards, stock based compensation 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 shorter than the remaining term. For market-based awards, stock-based compensation expense 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 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 was determined to be complete. We likewise charged our related costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matched these costs to the timing of expected revenues, where appropriate, or charged these costs to the accounting period in which they were incurred where it was not appropriate to capitalize or defer them to match with revenues. Derivative Instruments. The Company has used and may continue to use 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 fair value amounts for derivative instruments executed with the same counterparty, where such transactions are covered by an ISDA master agreement that 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 are intended to provide an economic hedge of the Company’s exposure to commodity price volatility, the Company has not attempted to qualify its derivative instruments for hedge accounting treatment. As a result, changes in the fair value of derivative instruments are recognized as gains or losses 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 counterparties as a result of derivative settlements are classified as cash flows from investing activities rather than operating 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 (net of salvage values) 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. 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 amount of tax benefit that has a greater than 50% likelihood 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 available to common stockholders by the weighted-average number of common shares outstanding during the period. 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 potentially dilutive common shares had been issued. Potentially dilutive common shares are our outstanding stock options and contingent restricted common stock. We use the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. Under this method, exercise of stock options and, under certain conditions, contingent restricted common stock is assumed to have occurred at the beginning of the period (or at time of issuance, if later) and common shares are assumed to have been issued. The proceeds from exercise of stock options and unamortized stock compensation expense related to restricted common stock are assumed to be used to repurchase common stock at the average market price during the period. The incremental shares (the difference between the number of shares assumed issued and the number of shares assumed repurchased) are included in the denominator of the diluted EPS computation. Contingent restricted stock is included in the computation of diluted shares, if dilutive, when the underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered satisfied if the end of the reporting period were the end of the related contingency period. New Accounting Pronouncements Not Yet Adopted. In August 2015, the Financial Accounting Standards Board ("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") by one year and allows 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 is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the full retrospective or modified retrospective transition methods. We expect to adopt this standard using the modified retrospective method. The Company expects that additional disclosures will be required as a result of adopting ASU 2014-09 and is currently assessing the impact of the guidance on its consolidated financial statements. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01"). The pronouncement requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. These changes become effective for fiscal years beginning after December 15, 2017. The expected adoption method of ASU 2016-01 is being evaluated by the Company and the adoption is not expected to have a significant impact on the Company’s consolidated financial position or results of operations. 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 twelve 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 consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted, provided that it is adopted in its entirety in the same period. Currently, the Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows. New Accounting Pronouncements Adopted. The Company early adopted ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, to be applied prospectively effective for the three months ended September 30, 2016, the first quarter of our fiscal year. This amended guidance simplifies the balance sheet position presentation and reduces complexity in accounting for deferred income tax assets and liabilities. The update requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. As a result, current deferred tax assets have been combined with noncurrent deferred income tax liabilities in the June 30, 2017 consolidated balance sheet. The prior periods presented were not retroactively adjusted. The Company early adopted ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting, effective for the three months ended September 30, 2016. This amended guidance simplifies and improves several aspects of the accounting for employee share-based payment transactions. Under previous guidance excess tax benefits were recognized as paid in capital to the extent they reduced cash taxes otherwise payable, and tax deficiencies were recognized as an offset to accumulated excess benefits, if any, or in the statement of operations. The new guidance requires companies to record excess tax benefits and tax deficiencies as income tax benefit or expense in the statements of operations when the awards vest or are settled. Under the required modified retrospective transition, the Company had no cumulative-effect adjustment to retained earnings at the beginning of the period of adoption, as its accumulated excess tax benefits had been completely used in reducing taxable income for the year ended June 30, 2016. For vestings that occurred during the year ended June 30, 2017, a related tax deficiency of $27,884 was recognized in income tax expense. The Company also elected to prospectively adopt the presentation of excess tax benefits in the operating section of the statements of cash flows. Accordingly, such statements for pre-adoption periods will continue to present excess tax benefits in the financing section. The amended guidance permits entities to make an accounting policy election related to how forfeitures will impact the recognition of compensation cost for stock-based compensation. Entities can continue to estimate the number of awards which are expected to be forfeited prior to the end of the service period as currently required or can elect to account for forfeitures as they occur. Upon early adoption, the Company elected to change its accounting policy to account for forfeitures as they occur. Except for the effect on income tax expense mentioned above, none of the other provisions in this amended guidance had a material impact on our consolidated financial statements.

Dehli Field Litigation Settlement	12 Months Ended
Dehli Field Litigation Settlement	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Dehli Field Litigation Settlement	Delhi Field Litigation Settlement On June 24, 2016, we entered into a settlement agreement with Denbury Resources, Inc., operator of the Delhi field, to resolve all outstanding disputes and claims between the parties, including litigation between Evolution and Denbury with respect to the Delhi field in northeastern Louisiana. The 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 to Evolution, 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. As part of the settlement, Evolution conveyed a 0.2226% (.002226) overriding royalty interest in the Delhi field to Denbury.

Receivables

12 Months Ended

Jun. 30, 2017

Receivables [Abstract]

Receivables

As of June 30, 2017 and 2016 our receivables consisted of the following:



	June 30, 2017		June 30, 2016
Receivables from oil and gas sales	$	2,722,880	$	2,637,593
Other	3,822		595
Total receivables	$	2,726,702	$	2,638,188

There were no losses from uncollectible accounts receivable, nor any allowance for doubtful accounts in any of the periods presented in these financial statements.

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Prepaid Expenses and Other Current Assets

12 Months Ended

Jun. 30, 2017

Prepaid Expenses and Other Current Assets

As of June 30, 2017 and 2016 our prepaid expenses and other current assets consisted of the following:



	June 30, 2017		June 30, 2016
Prepaid insurance	$	169,416	$	168,681
Prepaid federal and state income taxes	121,232		—
Retainers and deposits	7,553		30,568
Derivative assets, net	—		14,132
Other prepaid expenses	89,471		52,500
Prepaid expenses and other current assets	$	387,672	$	265,881

Property and Equipment

12 Months Ended

Jun. 30, 2017

Property, Plant and Equipment [Abstract]

Property and Equipment

As of June 30, 2017 and 2016, our oil and natural gas properties and other property and equipment consisted of the following:



	June 30, 2017			June 30, 2016
Oil and natural gas properties
Property costs subject to amortization	$	84,962,933		$	77,408,353
Less: Accumulated depreciation, depletion, and amortization	(23,172,865		)	(17,437,890		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	61,790,068			59,970,463
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	135,377			235,752
Less: Accumulated depreciation	(94,688		)	(207,103		)
Other property and equipment, net	$	40,689		$	28,649

As of June 30, 2017 and 2016, all oil and gas property costs were being amortized.

During the year ended June 30, 2017, the Company incurred capital expenditures of $7.1 million for the Delhi field, including approximately $4.8 million for the NGL plant project. We have incurred approximately $26.3 million on a cumulative basis for the NGL plant.

Other Assets

12 Months Ended

Jun. 30, 2017

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Assets

As of June 30, 2017 and 2016, our other assets consisted of the following:



	June 30, 2017			June 30, 2016
Royalty rights	108,512			108,512
Less: Accumulated amortization of royalty rights	(20,346		)	(6,782		)
Investment in Well Lift Inc., at cost	108,750			108,750
Deferred loan costs	168,972			168,972
Less: Accumulated amortization of deferred loan costs	(70,504		)	(13,963		)
Other assets, net	$	295,384		$	365,489

For further details about our royalty rights and investment in Well Lift Inc. ("WLI"), see Note 7 – Restructuring. These assets were recorded in connection with the separation of our artificial lift technology operations. The Company accounts for its investment in WLI using the cost method, under which any return of capital reduces cost and any dividends paid are recorded as income. Investment value is evaluated for impairment at least quarterly or when management identifies any events or changes in circumstances that may have a significant adverse effect on the fair value of the investment. There is no published market value for this private investment, so it is not practicable to value it at fair market value on a periodic basis.

In April 2016, we entered into a new secured credit facility, incurring $168,972 of deferred loan costs. Our previous credit facility had deferred loan costs of $179,468, which were fully amortized at its expiration in April 2016. During the year ended June 30, 2016, negotiations to obtain a new expanded secured credit facility from our previous lender were curtailed due to market conditions. We determined that $50,414 of deferred legal fees related to this 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 were charged to capitalized costs of oil and gas properties. Amortization of deferred loan costs related to our credit facilities for the years ended June 30, 2017, 2016 and 2015 was $56,541, $46,374 and $48,636, respectively.

Restructuring	12 Months Ended
Restructuring	Jun. 30, 2017
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. All of such accrued separation and benefits costs had been settled as of June 30, 2017, and an adjustment of $4,488 was recorded in the current year to reflect the difference between the original accrual and actual expenditures. Other Restructuring Impairments Also in connection with the December 2015 separation of GARP^®, 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 technology assets to our estimate of their expected discounted net present value, which was $108,512. This resulted in an impairment charge of $469,395. In addition, we transferred certain inventory and minor fixed assets to WLI that 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 totaled $569,228 and are included in restructuring charges.

Accrued Liabilities and Other

12 Months Ended

Jun. 30, 2017

Other Liabilities Disclosure [Abstract]

Accrued Liabilities and Other

As of June 30, 2017 and 2016 our accrued liabilities and other consisted of the following:



	June 30, 2017		June 30, 2016
Accrued incentive and other compensation	$	413,113	$	999,172
Accrued restructuring charges	—		419,488
Asset retirement obligations due within one year	35,115		201,896
Accrued royalties, including suspended accounts	17,708		49,580
Accrued franchise taxes	150,062		62,834
Payable for settled derivatives	—		318,708
Accrued - other	1,841		46,273
Accrued liabilities and other	$	617,839	$	2,097,951

Asset Retirement Obligations

12 Months Ended

Jun. 30, 2017

Asset Retirement Obligation Disclosure [Abstract]

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 obligations for the years ended June 30, 2017 and 2016:



	Years Ended June 30,
	2017			2016
Asset retirement obligations—beginning of period	$	962,196		$	772,990
Liabilities incurred	52,792			28,505
Liabilities settled	(157,164		)	—
Liabilities sold (b)	(47,817		)	—
Accretion of discount	59,664			49,054
Revisions to previous estimates	419,072			111,647
Asset retirement obligations — end of period (b)	1,288,743			962,196
Less current asset retirement obligations	(35,115		)	(201,896		)
Long-term portion of asset retirement obligations	$	1,253,628		$	760,300

(a) We conveyed our interest in a well to the previous operator in exchange for the assumption of our asset retirement obligations.

(b) As we have now retired all of our remaining operated wells, our asset retirement obligations as of June 30, 2017 consist entirely of our working interest obligations in the Delhi field.

Stockholders' Equity	12 Months Ended
Stockholders' Equity	Jun. 30, 2017
Equity [Abstract]
Stockholders' Equity	Stockholders' Equity Common Stock As of June 30, 2017, we had 33,087,308 shares of common stock outstanding. 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. This rate was subsequently adjusted to $0.05 per share during the quarter ended March 31, 2015. During the year ended June 30, 2017, the Board of Directors made two increases to the quarterly cash dividend, resulting in rates of $0.065 per share for the December 31, 2016 dividend payment and $0.07 per share for the March 31, 2017 dividend payment. We paid total cash dividends of $8,432,435, $6,565,823 and $9,833,642 to our common shareholders during the years ended June 30, 2017, 2016 and 2015, respectively. In May 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. As of June 30, 2017, we have repurchased 265,762 shares at an average price of $6.05 per share, for total cost of $1,609,008. 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, 2017, the Company acquired 83,675 shares of treasury stock at an average cost of $6.42 per share (totaling $537,014) from holders of newly vested stock-based awards to fund the recipients' payroll taxes paid in the year. The treasury shares were subsequently canceled. During the year ended June 30, 2016, the Company purchased 202,390 shares of treasury stock at an average cost of $5.80 per share (totaling $1,173,899) under its share repurchase program and also acquired 16,292 shares of treasury stock at an average cost of $5.49 per share (totaling $89,503) from holders of newly vested stock-based awards to fund the recipients' payroll taxes paid in the year. All treasury shares were subsequently canceled. During the year ended June 30, 2015, the Company purchased 63,372 shares of treasury stock at an average cost of $6.87 per share (totaling $435,109) under its share repurchase program and also acquired 7,535 shares of treasury stock at an average cost of $9.16 per share (totaling $69,015) from holders of newly vested stock-based awards to fund the recipients' payroll taxes paid in the year. All treasury shares were subsequently canceled. Series A Cumulative Perpetual Preferred Stock Called for Redemption On September 30, 2016, the Company elected to redeem all 317,319 outstanding shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock. The redemption occurred on November 14, 2016 at the redemption value of $25.00 per share plus all accumulated and unpaid distributions, for an aggregate redemption cost of $7,932,975. On September 30, 2016, in connection with the planned redemption, the Company recorded a deemed dividend of $1,002,440, representing the difference between the redemption consideration paid and the historical net issuance proceeds of the preferred shares. Accordingly, net income was adjusted for this deemed dividend to determine net income attributable to common shareholders and earnings per common share. Dividends on the Series A Cumulative Preferred Stock accrued and accumulated at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly. During the year ended June 30, 2017, we paid cash dividends of $250,990 to holders of our Series A Preferred Stock. During each of the years ended June 30, 2016 and 2015, we paid cash dividends of $674,302. Tax Treatment of Dividends to Recipients Based on our current projections for the fiscal year ending June 30, 2017, we expect all preferred and common dividends to be treated for tax purposes as qualified dividend income to the recipients. For the fiscal year ended June 30, 2016, all preferred and common dividends for this fiscal year were treated for tax purposes as qualified dividend income to the recipients. For 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.

Stock-Based Compensation

12 Months Ended

Jun. 30, 2017

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation

At the December 8, 2016 annual meeting, the stockholders approved the adoption of the Evolution Petroleum Corporation 2016 Equity Incentive Plan (the “2016 Plan”), which replaced the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,000 shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be granted to employees, directors and consultants of the Company in any one or a combination of the following forms: incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock, including its appreciation in value. As of June 30, 2017, 1,100,000 shares were available for grant under the 2016 Plan.

At June 30, 2017, no shares remained available for grant under the 2004 Plan. We were authorized to issue 6,500,000 shares of common stock prior to its expiration on October 24, 2017. In connection with the adoption of the 2016 Plan, the Board terminated the 2004 Plan on December 8, 2016 and 32,146 remaining reserved shares were released to the Company's authorized but unissued and unreserved shares. All outstanding awards granted under the 2004 Plan continue to be subject to the terms and conditions as set forth in the agreements evidencing such awards and the terms of the 2004 Plan. Under these agreements, 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.

Stock Options

No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. The following summary presents information regarding outstanding Stock Options as of June 30, 2017, and the changes during the period:



	Number of Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Term (in years)
Stock Options outstanding at July 1, 2016	35,231		$	2.19
Exercised	(35,231	)	2.19
Stock Options outstanding at June 30, 2017	—		$	—	$	—	0.0

For the year ended June 30, 2017, there were 35,231 Stock Options exercised with an aggregate intrinsic value of $188,821. 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.

No stock options vested during the years ended June 30, 2017, 2016, and 2015.

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 amortized over the service period.

In August 2014, December 2015 and September 2016, 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, 2017, 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 granted in 2016 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 an index consisting of designated peer companies during defined measurement periods. Market-based awards granted in fiscal 2015 and 2016 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. Vesting of market-based awards granted in fiscal 2017 is based on the Company's total common stock return compared to a peer group of sixteen companies in our industry with comparable market capitalizations. During the fiscal year ended June 30, 2017, we granted market-based awards with grant date fair values ranging from $3.42 to $5.62 per share, all with an expected vesting period of 2.83 years, based on the various quartiles of comparable market performance. 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 with expected vesting periods of 2.55 to 3.30 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.

Unvested Restricted Stock awards at June 30, 2017 consisted of the following:



Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	217,922	$	7.03
Performance-based awards	54,475	5.67
Market-based awards	119,227	4.97
Unvested Restricted Stock at June 30, 2017	391,624	$	6.22

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2017:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2017		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2016	406,848		$	6.74	$	—
Service-based awards granted	86,563		7.02
Performance-based awards granted	54,475		5.67
Market-based awards granted	54,475		5.44
Vested	(210,737	)	7.22
Unvested Restricted Stock at June 30, 2017	391,624		$	6.22	$	1,648,297	2.0

During the years ended June 30, 2017, 2016, and 2015, there were 210,737, 86,719, and 91,306 shares of Restricted Stock that vested with a total grant date fair value of $1,520,569, $757,229, and $766,970, respectively.

Unvested Contingent Restricted Stock awards at June 30, 2017 consisted of the following:



Award Type	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	39,403	$	7.02
Market-based awards	73,867	3.37
Unvested Contingent Restricted Stock at June 30, 2017	113,270	$	4.64

The following table summarizes Contingent Restricted Stock activity:



	Number of Restricted Stock Units		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2017 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2016	91,172		$	5.21
Performance-based awards granted	27,237		5.67
Market-based awards granted	27,237		3.42
Vested	(32,376	)	$	6.09
Unvested Contingent Restricted Stock at June 30, 2017	113,270		$	4.64	$	121,668	2.1

(1) Excludes $276,702 of potential future compensation expense for 39,403 shares of 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, 2017, 2016, and 2015, we recognized stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants of $1,180,618, $1,809,548, and $943,653, respectively. Expense for June 30, 2016 includes $59,339 of stock-based compensation that was incurred in a restructuring.

Supplemental Disclosure of Cash Flow Information

12 Months Ended

Jun. 30, 2017

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosure of Cash Flow Information

Our supplemental disclosures of cash flow information for the years ended June 30, 2017, 2016, and 2015 are as follows:



	June 30,
	2017			2016			2015
Income taxes paid	$	1,495,377		$	540,000		$	220,000
Income tax refunds	—			1,556,999			331,733
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	(3,076,245		)	(2,250,048		)	5,422,566
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	471,864			140,151			576,039
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	$	77,156		$	76,500		$	—
Accrued purchases of treasury stock	—			(170,283		)	170,283

Income Taxes

12 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

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, 2017, 2016 and 2015. 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, 2014 through June 30, 2016 for federal tax purposes and for the years ended June 30, 2013 through June 30, 2016 for state tax purposes.

The components of our income tax provision are as follows:



	June 30, 2017		June 30, 2016		June 30, 2015
Current:
Federal	$	168,152	$	8,731,290	$	1,413,296
State	581,593		264,254		608,436
Total current income tax provision	749,745		8,995,544		2,021,732
Deferred:
Federal	3,880,522		541,891		1,282,059
State	210,397		33,344		140,430
Total deferred income tax provision	4,090,919		575,235		1,422,489
	$	4,840,664	$	9,570,779	$	3,444,221

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. Our effective tax rate for 2017 exceeded the statutory rate primarily as a result of state of Louisiana income taxes, partly offset by depletion in excess of basis. 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 and the Company had significant legal settlement and derivative gains that were not taxable in Louisiana. The effective tax rates for 2015 exceeded the statutory rate primarily due to state of Louisiana income taxes.



	June 30, 2017			% of Income Before Income Taxes		June 30, 2016			% of Income Before Income Taxes		June 30, 2015			% of Income Before Income Taxes
Income tax provision computed at the statutory federal rate	$	4,380,892		34.0	%	$	11,638,588		34.0	%	$	2,868,267		34.0	%
Reconciling items:
Depletion in excess of basis	(92,196		)	(0.7	)%	(2,242,620		)	(6.6	)%	—			—	%
State income taxes, net of federal tax benefit	522,713			4.1	%	196,415			0.6	%	595,708			7.1	%
Permanent differences related to stock-based compensation	27,884			0.2	%	—			—	%	—			—	%
Other	1,371			—	%	(21,604		)	(0.1	)%	(19,754		)	(0.2	)%
Income tax provision	$	4,840,664		37.6	%	$	9,570,779		27.9	%	$	3,444,221		40.9	%

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, 2017			June 30, 2016			June 30, 2015
Deferred tax assets:
Non-qualified stock-based compensation	$	367,159		$	553,182		$	173,647
Net operating loss carry-forwards	852,477			386,808			400,288
AMT credit carry-forward	110,564			—			701,254
Other	18,581			130,947			91,113
Gross deferred tax assets	1,348,781			1,070,937			1,366,302
Valuation allowance	(292,446		)	(292,446		)	(292,446		)
Total deferred tax assets	1,056,335			778,491			1,073,856
Deferred tax liability:
Oil and natural gas properties	(16,882,626		)	(12,513,863		)	(12,233,993		)
Total deferred tax liability	(16,882,626		)	(12,513,863		)	(12,233,993		)
Net deferred tax liability	$	(15,826,291	)	$	(11,735,372	)	$	(11,160,137	)

The above assets and liabilities are present on the balance sheet as follows:



	June 30, 2017		June 30, 2016		June 30, 2015
Current deferred tax asset	$	—	$	105,321	$	82,414
Non-current deferred tax liability	15,826,291		11,840,693		11,242,551
Net liability	15,826,291		11,735,372		11,160,137

As the result of early adopting ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, at the beginning of this fiscal year current deferred tax assets have been netted together with noncurrent deferred income tax liabilities on the June 30, 2017 consolidated balance sheet. The prior years presented have not been retrospectively adjusted.

As of June 30, 2017, 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 this fiscal year we generated a net operating loss of approximately $9.1 million in the State of Louisiana reflecting bonus depreciation tax deductions for our NGL plant, which was placed in service during fiscal 2017.

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 and 2015, 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 and $1,633,946 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, 2017, the Company had an estimated carryforward of percentage depletion in excess of basis of approximately $7.2 million. These future deductions are limited to 65% of taxable income in any period.

Related Party Transactions	12 Months Ended
Related Party Transactions	Jun. 30, 2017
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 and 2015, we made payments of $0 and $26,579, 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 WLI discussed in Note 7.

Net Income Per Share

12 Months Ended

Jun. 30, 2017

Earnings Per Share [Abstract]

Net Income Per Share

The following table sets forth the computation of basic and diluted net income per share:



	June 30,
	2017		2016		2015
Numerator
Net income attributable to common shareholders	$	6,790,883	$	23,986,060	$	4,317,555
Denominator
Weighted average number of common shares – Basic	33,034,480		32,810,375		32,817,456
Effect of dilutive securities:
Contingent restricted stock grants	53,546		9,378		4,422
Stock Options	22,534		41,478		102,140
Total weighted average dilutive securities	76,080		50,856		106,562
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,110,560		32,861,231		32,924,018
Net income per common share – Basic	$	0.21	$	0.73	$	0.13
Net income per common share – Diluted	$	0.21	$	0.73	$	0.13

The following were reflected in the calculation of diluted earnings per share as of June 30, 2017:

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 June 30, 2016
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 June 30, 2015
Contingent Restricted Stock grants	$	—	56,286
Stock Options	2.50		91,061
Total	$	1.55	147,347

Credit Agreements	12 Months Ended
Credit Agreements	Jun. 30, 2017
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 expired in April 2016. The initial borrowing base under the Facility was set at $10,000,000 and the Company has no outstanding borrowings. Borrowings 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 over the term of the facility. The unamortized balance in debt issuance costs related to the Facility was $98,468 as of June 30, 2017. 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 in the prior fiscal year.

Commitments and Contingencies

12 Months Ended

Jun. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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’ land in Winn Parish. The plaintiffs requested monetary damages and other relief. The plaintiffs subsequently filed an amended petition joining the Company as defendants in its capacity as parent company of NGS Sub Corp. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. The district court dismissed the claim of Brooks against NGS Sub Corp. and the Company because Brooks purchased the land where the well is located subsequent to the divestiture of the property by NGS Sub. Corp. The claim of Hawkins is still being defended. Trial is currently scheduled for March 2018. We will continue to vigorously defend the claims and after consultation with our legal counsel, we consider the likelihood of a material loss to the Company in this matter to be remote.

Lease Commitments. During the year ended June 30, 2017, our previous lease for office space ended and we moved into smaller office space and entered into a non-cancelable lease that expires on May 31, 2019. Future minimum lease commitments as of June 30, 2017 under our office lease are as follows:



For the fiscal year ended June 30,
2018	$	73,073
2019	66,984
Total	$	140,057

Rent expense for the years ended June 30, 2017, 2016, and 2015 was $80,472, $182,626, and $175,103, respectively.

Concentrations of Credit Risk

12 Months Ended

Jun. 30, 2017

Risks and Uncertainties [Abstract]

Concentrations of Credit Risk

Major Customers. Historically 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 and NGL production from Delhi. Although we have the right to take our working interest production at Delhi in-kind, we are currently selling our production under the Delhi operator's agreement with Plains Marketing L.P. and American Midstream for the sale of our oil and NGL's, respectively 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 of our net oil and natural gas revenues during the years ended June 30, 2017, 2016, and 2015. The loss of our purchasers 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.



	Year Ended June 30,
Customers	2017		2016		2015
Plains Marketing L.P. (Oil sales from Delhi)	97	%	99	%	99	%
American Midstream Gas Solutions (NGL sales from Delhi)	3	%	—	%	—	%
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	12 Months Ended
Retirement Plan	Jun. 30, 2017
Retirement Benefits [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 cash contributions fully vested when made. Our matching contributions to the Plan totaled $53,113, $88,348, and $85,676 for the years ended June 30, 2017, 2016, and 2015, respectively.

Derivatives	12 Months Ended
Derivatives	Jun. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives In 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 Hedging ("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. At June 30, 2017, the Company had no derivative asset or liability positions. At June 30, 2016, the Company held a derivative instrument net asset position with its counterparty that had a fair value of $14,132. 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, 2017, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $29,758 consisting of a realized gain of $43,890 on settled derivatives and an unrealized loss of $14,132 on unsettled derivatives. 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 which included 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.

Fair Value Measurement

12 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

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. At June 30, 2017, the Company had no derivative instruments and, accordingly, there were no derivative assets and liabilities presented in the year end balance sheet. The following table summarizes the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the June 30, 2016 consolidated balance sheet. 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 Sheet
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.

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)

12 Months Ended

Jun. 30, 2017

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 related to 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 $471,864, $140,151 and $576,039 during the years ended June 30, 2017, 2016, and 2015, respectively.



	For the Years Ended June 30,
	2017		2016		2015
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	—	$	—	$	—
Unproved property (a)	—		596,500		—
Exploration costs	—		—		—
Development costs	7,554,579		19,093,200		10,975,637
Total costs incurred for oil and natural gas activities	$	7,554,579	$	19,689,700	$	10,975,637

(a) As described in Note 17 — 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. Reserves volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2017, 2016, and 2015, 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 life of the property, when estimating whether reserves 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, 2014	10,526,344		2,278,688		2,906,863		13,289,510
Revisions of previous estimates (a)	(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 (b)	(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
Revisions of previous estimates (c)	508,123		(504,733	)	16		3,390
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(724,523	)	(43,907	)	(16	)	(768,433	)
June 30, 2017	8,372,150		1,686,231		—		10,058,378
Proved developed reserves:
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
June 30, 2017	6,617,389		1,332,803		—		7,950,192
Proved undeveloped reserves:
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
June 30, 2017	1,754,761		353,425		—		2,108,186

(a) The 2,894,703 revision for natural gas in fiscal 2015 primarily reflects a 2,246,524 MCF reduction for the Delhi field NGL plant together with a 452,786 MCF revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision to change in the plant design 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 from the lost Giddings well.

(b) 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.

(c) The positive crude oil revision resulted from better production performance during fiscal 2017 and the expectation of greater ultimate recoveries of oil from the Delhi field. The negative NGL revision results primarily from lower expectations for ultimate NGL recoveries from the plant based on production data after the plant commenced production.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales and production and development costs have been estimated using, respectively, trailing 12 month unweighted arithmetic average first-day-of-the-month 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, 2017, 2016, and 2015 are as follows:



	For the Years Ended June 30,
	2017			2016			2015
Future cash inflows	$	425,094,736		$	383,491,193		$	807,030,282
Future production costs and severance taxes	(213,115,443		)	(179,182,565		)	(309,225,333		)
Future development costs	(22,631,856		)	(16,595,047		)	(49,691,006		)
Future income tax expenses	(47,055,551		)	(45,713,438		)	(123,888,665		)
Future net cash flows	142,291,886			142,000,143			324,225,278
10% annual discount for estimated timing of cash flows	(59,354,333		)	(64,042,824		)	(165,028,739		)
Standardized measure of discounted future net cash flows	$	82,937,553		$	77,957,319		$	159,196,539

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,
	2017			2016			2015
	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	48.85	n/a	$	42.91	n/a	$	71.88	$	3.44

There were no natural gas reserves in 2017 and 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.

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,
	2017			2016			2015
Balance, beginning of year	$	77,957,319		$	159,196,539		$	226,077,672
Net changes in sales prices and production costs related to future production	19,821,288			(120,832,747		)	(88,043,095		)
Changes in estimated future development costs	(1,626,833		)	74,991			(9,585,405		)
Sales of oil and gas produced during the period, net of production costs	(23,649,087		)	(17,079,363		)	(18,538,016		)
Net change due to extensions, discoveries, and improved recovery	—			—			—
Net change due to revisions in quantity estimates	(2,206,287		)	(18,821,014		)	(9,391,321		)
Net change due to sales of minerals in place	—			—			—
Development costs incurred during the period	2,632,547			16,327,883			7,785,095
Accretion of discount	10,086,904			21,870,650			31,974,540
Net change in discounted income taxes	(5,045,279		)	36,598,239			34,157,767
Net changes in timing of production and other	4,966,981			622,141			(15,240,698		)
Balance, end of year	$	82,937,553		$	77,957,319		$	159,196,539

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Jun. 30, 2017

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

The following table presents summarized quarterly financial information for the years ended June 30, 2017 and 2016:



2017	First		Second		Third		Fourth
Revenues	$	7,593,940	$	8,529,817	$	9,525,437	$	8,835,702
Operating income	2,727,593		3,675,381		3,893,236		2,583,912
Net income available to common shareholders	$	563,345	$	2,307,634	$	2,419,143	$	1,500,761
Basic and diluted net income per share	$	0.02	$	0.07	$	0.07	$	0.05

Dividends per share declared and paid in the quarter	$	0.05	$	0.065	$	0.070	$	0.070



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 and diluted net income (loss) per share	$	0.09	$	0.02		$	(0.01	)	$	0.63

Dividends per share declared and paid in the quarter	$	0.05	$	0.05		$	0.05		$	0.05

(1) Includes $1.3 million restructuring charge.

(2) Includes gain on settlement of Delhi field litigation of $28.1 million.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Jun. 30, 2017
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 7, 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 (a) 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, (b) asset retirement obligations, (c) stock-based compensation, (d) fair values of derivative assets and liabilities, (e) income taxes and the valuation of deferred tax assets and (f) 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.
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, 2017, 2016 or 2015.
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. These assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which was depreciated using a method which approximated 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. We estimate the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. Service-based and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. Market-based awards are valued using a Monte Carlo simulation based on the historical volatility of the Company's total stock return compared to the historical volatilities of other companies or indices to which we compare our performance. This Monte Carlo simulation also provides an expected vesting period. We use the Black-Scholes option-pricing model to determine grant date fair value of any Stock Option or Incentive Warrant awards. For service-based awards, stock-based compensation is recognized ratably over the service period. For performance-based awards, stock based compensation 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 shorter than the remaining term. For market-based awards, stock-based compensation expense 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 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 was determined to be complete. We likewise charged our related costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matched these costs to the timing of expected revenues, where appropriate, or charged these costs to the accounting period in which they were incurred where it was not appropriate to capitalize or defer them to match with revenues.
Derivative Instruments	Derivative Instruments. The Company has used and may continue to use 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 fair value amounts for derivative instruments executed with the same counterparty, where such transactions are covered by an ISDA master agreement that 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 are intended to provide an economic hedge of the Company’s exposure to commodity price volatility, the Company has not attempted to qualify its derivative instruments for hedge accounting treatment. As a result, changes in the fair value of derivative instruments are recognized as gains or losses 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 counterparties as a result of derivative settlements are classified as cash flows from investing activities rather than operating 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 (net of salvage values) 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.
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 amount of tax benefit that has a greater than 50% likelihood 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 available to common stockholders by the weighted-average number of common shares outstanding during the period. 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 potentially dilutive common shares had been issued. Potentially dilutive common shares are our outstanding stock options and contingent restricted common stock. We use the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. Under this method, exercise of stock options and, under certain conditions, contingent restricted common stock is assumed to have occurred at the beginning of the period (or at time of issuance, if later) and common shares are assumed to have been issued. The proceeds from exercise of stock options and unamortized stock compensation expense related to restricted common stock are assumed to be used to repurchase common stock at the average market price during the period. The incremental shares (the difference between the number of shares assumed issued and the number of shares assumed repurchased) are included in the denominator of the diluted EPS computation. Contingent restricted stock is included in the computation of diluted shares, if dilutive, when the underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered satisfied if the end of the reporting period were the end of the related contingency period.
Recent Accounting Pronouncements	New Accounting Pronouncements Not Yet Adopted. In August 2015, the Financial Accounting Standards Board ("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") by one year and allows 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 is now effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the full retrospective or modified retrospective transition methods. We expect to adopt this standard using the modified retrospective method. The Company expects that additional disclosures will be required as a result of adopting ASU 2014-09 and is currently assessing the impact of the guidance on its consolidated financial statements. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities ("ASU 2016-01"). The pronouncement requires equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for financial instruments measured at amortized cost. These changes become effective for fiscal years beginning after December 15, 2017. The expected adoption method of ASU 2016-01 is being evaluated by the Company and the adoption is not expected to have a significant impact on the Company’s consolidated financial position or results of operations. 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 twelve 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 consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. This standard will be effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years with early adoption permitted, provided that it is adopted in its entirety in the same period. Currently, the Company does not expect the impact of adopting ASU 2016-15 to have a material effect on its consolidated statements of cash flows. New Accounting Pronouncements Adopted. The Company early adopted ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes, to be applied prospectively effective for the three months ended September 30, 2016, the first quarter of our fiscal year. This amended guidance simplifies the balance sheet position presentation and reduces complexity in accounting for deferred income tax assets and liabilities. The update requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. As a result, current deferred tax assets have been combined with noncurrent deferred income tax liabilities in the June 30, 2017 consolidated balance sheet. The prior periods presented were not retroactively adjusted. The Company early adopted ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting, effective for the three months ended September 30, 2016. This amended guidance simplifies and improves several aspects of the accounting for employee share-based payment transactions. Under previous guidance excess tax benefits were recognized as paid in capital to the extent they reduced cash taxes otherwise payable, and tax deficiencies were recognized as an offset to accumulated excess benefits, if any, or in the statement of operations. The new guidance requires companies to record excess tax benefits and tax deficiencies as income tax benefit or expense in the statements of operations when the awards vest or are settled. Under the required modified retrospective transition, the Company had no cumulative-effect adjustment to retained earnings at the beginning of the period of adoption, as its accumulated excess tax benefits had been completely used in reducing taxable income for the year ended June 30, 2016. For vestings that occurred during the year ended June 30, 2017, a related tax deficiency of $27,884 was recognized in income tax expense. The Company also elected to prospectively adopt the presentation of excess tax benefits in the operating section of the statements of cash flows. Accordingly, such statements for pre-adoption periods will continue to present excess tax benefits in the financing section. The amended guidance permits entities to make an accounting policy election related to how forfeitures will impact the recognition of compensation cost for stock-based compensation. Entities can continue to estimate the number of awards which are expected to be forfeited prior to the end of the service period as currently required or can elect to account for forfeitures as they occur. Upon early adoption, the Company elected to change its accounting policy to account for forfeitures as they occur. Except for the effect on income tax expense mentioned above, none of the other provisions in this amended guidance had a material impact on our consolidated financial statements.
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. At June 30, 2017, the Company had no derivative instruments and, accordingly, there were no derivative assets and liabilities presented in the year end balance sheet. The following table summarizes the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the June 30, 2016 consolidated balance sheet. All items included in the tables below are Level 2 inputs within the fair value hierarchy:

Receivables (Tables)

12 Months Ended

Jun. 30, 2017

Receivables [Abstract]

Schedule of receivables

As of June 30, 2017 and 2016 our receivables consisted of the following:



	June 30, 2017		June 30, 2016
Receivables from oil and gas sales	$	2,722,880	$	2,637,593
Other	3,822		595
Total receivables	$	2,726,702	$	2,638,188

Prepaid Expenses and Other Current Assets (Tables)

12 Months Ended

Jun. 30, 2017

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of prepaid expenses and other current assets

As of June 30, 2017 and 2016 our prepaid expenses and other current assets consisted of the following:



	June 30, 2017		June 30, 2016
Prepaid insurance	$	169,416	$	168,681
Prepaid federal and state income taxes	121,232		—
Retainers and deposits	7,553		30,568
Derivative assets, net	—		14,132
Other prepaid expenses	89,471		52,500
Prepaid expenses and other current assets	$	387,672	$	265,881

Property and Equipment (Tables)

12 Months Ended

Jun. 30, 2017

Property, Plant and Equipment [Abstract]

Schedule of oil and natural gas properties and other property and equipment

As of June 30, 2017 and 2016, our oil and natural gas properties and other property and equipment consisted of the following:



	June 30, 2017			June 30, 2016
Oil and natural gas properties
Property costs subject to amortization	$	84,962,933		$	77,408,353
Less: Accumulated depreciation, depletion, and amortization	(23,172,865		)	(17,437,890		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	61,790,068			59,970,463
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	135,377			235,752
Less: Accumulated depreciation	(94,688		)	(207,103		)
Other property and equipment, net	$	40,689		$	28,649

Other Assets (Tables)

12 Months Ended

Jun. 30, 2017

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of other assets

As of June 30, 2017 and 2016, our other assets consisted of the following:



	June 30, 2017			June 30, 2016
Royalty rights	108,512			108,512
Less: Accumulated amortization of royalty rights	(20,346		)	(6,782		)
Investment in Well Lift Inc., at cost	108,750			108,750
Deferred loan costs	168,972			168,972
Less: Accumulated amortization of deferred loan costs	(70,504		)	(13,963		)
Other assets, net	$	295,384		$	365,489

Accrued Liabilities and Other (Tables)

12 Months Ended

Jun. 30, 2017

Other Liabilities Disclosure [Abstract]

Other Current Liabilities

As of June 30, 2017 and 2016 our accrued liabilities and other consisted of the following:



	June 30, 2017		June 30, 2016
Accrued incentive and other compensation	$	413,113	$	999,172
Accrued restructuring charges	—		419,488
Asset retirement obligations due within one year	35,115		201,896
Accrued royalties, including suspended accounts	17,708		49,580
Accrued franchise taxes	150,062		62,834
Payable for settled derivatives	—		318,708
Accrued - other	1,841		46,273
Accrued liabilities and other	$	617,839	$	2,097,951

Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2017

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 obligations for the years ended June 30, 2017 and 2016:



	Years Ended June 30,
	2017			2016
Asset retirement obligations—beginning of period	$	962,196		$	772,990
Liabilities incurred	52,792			28,505
Liabilities settled	(157,164		)	—
Liabilities sold (b)	(47,817		)	—
Accretion of discount	59,664			49,054
Revisions to previous estimates	419,072			111,647
Asset retirement obligations — end of period (b)	1,288,743			962,196
Less current asset retirement obligations	(35,115		)	(201,896		)
Long-term portion of asset retirement obligations	$	1,253,628		$	760,300

(a) We conveyed our interest in a well to the previous operator in exchange for the assumption of our asset retirement obligations.

(b) As we have now retired all of our remaining operated wells, our asset retirement obligations as of June 30, 2017 consist entirely of our working interest obligations in the Delhi field.

Stock-Based Compensation (Tables)

12 Months Ended

Jun. 30, 2017

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, 2017, and the changes during the period:



	Number of Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value		Weighted Average Remaining Contractual Term (in years)
Stock Options outstanding at July 1, 2016	35,231		$	2.19
Exercised	(35,231	)	2.19
Stock Options outstanding at June 30, 2017	—		$	—	$	—	0.0

Schedule of Restricted Stock transactions

The following table summarizes Contingent Restricted Stock activity:



	Number of Restricted Stock Units		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2017 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2016	91,172		$	5.21
Performance-based awards granted	27,237		5.67
Market-based awards granted	27,237		3.42
Vested	(32,376	)	$	6.09
Unvested Contingent Restricted Stock at June 30, 2017	113,270		$	4.64	$	121,668	2.1

(1) Excludes $276,702 of potential future compensation expense for 39,403 shares of performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Unvested Restricted Stock awards at June 30, 2017 consisted of the following:



Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	217,922	$	7.03
Performance-based awards	54,475	5.67
Market-based awards	119,227	4.97
Unvested Restricted Stock at June 30, 2017	391,624	$	6.22

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2017:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2017		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2016	406,848		$	6.74	$	—
Service-based awards granted	86,563		7.02
Performance-based awards granted	54,475		5.67
Market-based awards granted	54,475		5.44
Vested	(210,737	)	7.22
Unvested Restricted Stock at June 30, 2017	391,624		$	6.22	$	1,648,297	2.0

Unvested Contingent Restricted Stock awards at June 30, 2017 consisted of the following:



Award Type	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	39,403	$	7.02
Market-based awards	73,867	3.37
Unvested Contingent Restricted Stock at June 30, 2017	113,270	$	4.64

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Jun. 30, 2017

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, 2017, 2016, and 2015 are as follows:



	June 30,
	2017			2016			2015
Income taxes paid	$	1,495,377		$	540,000		$	220,000
Income tax refunds	—			1,556,999			331,733
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	(3,076,245		)	(2,250,048		)	5,422,566
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	471,864			140,151			576,039
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	$	77,156		$	76,500		$	—
Accrued purchases of treasury stock	—			(170,283		)	170,283

Income Taxes (Tables)

12 Months Ended

Jun. 30, 2017

Income Tax Disclosure [Abstract]

Schedule of components of income tax provision (benefit)

The components of our income tax provision are as follows:



	June 30, 2017		June 30, 2016		June 30, 2015
Current:
Federal	$	168,152	$	8,731,290	$	1,413,296
State	581,593		264,254		608,436
Total current income tax provision	749,745		8,995,544		2,021,732
Deferred:
Federal	3,880,522		541,891		1,282,059
State	210,397		33,344		140,430
Total deferred income tax provision	4,090,919		575,235		1,422,489
	$	4,840,664	$	9,570,779	$	3,444,221

Schedule of reconciliation of statutory income tax expense to income tax provision



	June 30, 2017			% of Income Before Income Taxes		June 30, 2016			% of Income Before Income Taxes		June 30, 2015			% of Income Before Income Taxes
Income tax provision computed at the statutory federal rate	$	4,380,892		34.0	%	$	11,638,588		34.0	%	$	2,868,267		34.0	%
Reconciling items:
Depletion in excess of basis	(92,196		)	(0.7	)%	(2,242,620		)	(6.6	)%	—			—	%
State income taxes, net of federal tax benefit	522,713			4.1	%	196,415			0.6	%	595,708			7.1	%
Permanent differences related to stock-based compensation	27,884			0.2	%	—			—	%	—			—	%
Other	1,371			—	%	(21,604		)	(0.1	)%	(19,754		)	(0.2	)%
Income tax provision	$	4,840,664		37.6	%	$	9,570,779		27.9	%	$	3,444,221		40.9	%

Schedule of components of deferred taxes



	Asset (Liability)
	June 30, 2017			June 30, 2016			June 30, 2015
Deferred tax assets:
Non-qualified stock-based compensation	$	367,159		$	553,182		$	173,647
Net operating loss carry-forwards	852,477			386,808			400,288
AMT credit carry-forward	110,564			—			701,254
Other	18,581			130,947			91,113
Gross deferred tax assets	1,348,781			1,070,937			1,366,302
Valuation allowance	(292,446		)	(292,446		)	(292,446		)
Total deferred tax assets	1,056,335			778,491			1,073,856
Deferred tax liability:
Oil and natural gas properties	(16,882,626		)	(12,513,863		)	(12,233,993		)
Total deferred tax liability	(16,882,626		)	(12,513,863		)	(12,233,993		)
Net deferred tax liability	$	(15,826,291	)	$	(11,735,372	)	$	(11,160,137	)

The above assets and liabilities are present on the balance sheet as follows:



	June 30, 2017		June 30, 2016		June 30, 2015
Current deferred tax asset	$	—	$	105,321	$	82,414
Non-current deferred tax liability	15,826,291		11,840,693		11,242,551
Net liability	15,826,291		11,735,372		11,160,137

Net Income Per Share (Tables)

12 Months Ended

Jun. 30, 2017

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,
	2017		2016		2015
Numerator
Net income attributable to common shareholders	$	6,790,883	$	23,986,060	$	4,317,555
Denominator
Weighted average number of common shares – Basic	33,034,480		32,810,375		32,817,456
Effect of dilutive securities:
Contingent restricted stock grants	53,546		9,378		4,422
Stock Options	22,534		41,478		102,140
Total weighted average dilutive securities	76,080		50,856		106,562
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,110,560		32,861,231		32,924,018
Net income per common share – Basic	$	0.21	$	0.73	$	0.13
Net income per common share – Diluted	$	0.21	$	0.73	$	0.13

Schedule of outstanding potentially dilutive securities

The following were reflected in the calculation of diluted earnings per share as of June 30, 2017:

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 June 30, 2016
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 June 30, 2015
Contingent Restricted Stock grants	$	—	56,286
Stock Options	2.50		91,061
Total	$	1.55	147,347

Commitments and Contingencies (Tables)

12 Months Ended

Jun. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum lease commitments under the operating lease

Future minimum lease commitments as of June 30, 2017 under our office lease are as follows:



For the fiscal year ended June 30,
2018	$	73,073
2019	66,984
Total	$	140,057

Concentrations of Credit Risk (Tables)

12 Months Ended

Jun. 30, 2017

Risks and Uncertainties [Abstract]

Schedule of customers from whom the entity derived 10 percent or more of net oil and natural gas revenues

The following table identifies customers from whom we derived 10 percent or more of our net oil and natural gas revenues during the years ended June 30, 2017, 2016, and 2015. The loss of our purchasers 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.



	Year Ended June 30,
Customers	2017		2016		2015
Plains Marketing L.P. (Oil sales from Delhi)	97	%	99	%	99	%
American Midstream Gas Solutions (NGL sales from Delhi)	3	%	—	%	—	%
All others	—	%	1	%	1	%
Total	100	%	100	%	100	%

Fair Value Measurement (Tables)

12 Months Ended

Jun. 30, 2017

Fair Value Disclosures [Abstract]

Schedule of fair value assets and liabilities measured on recurring basis

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 Sheet
Current derivative assets	$	45,263		$	(31,131	)	$	14,132
Current derivative liabilities	(31,131		)	31,131			—
Total	$	14,132		$	—		$	14,132

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) (Tables)

12 Months Ended

Jun. 30, 2017

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



	For the Years Ended June 30,
	2017		2016		2015
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	—	$	—	$	—
Unproved property (a)	—		596,500		—
Exploration costs	—		—		—
Development costs	7,554,579		19,093,200		10,975,637
Total costs incurred for oil and natural gas activities	$	7,554,579	$	19,689,700	$	10,975,637

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, 2014	10,526,344		2,278,688		2,906,863		13,289,510
Revisions of previous estimates (a)	(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 (b)	(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
Revisions of previous estimates (c)	508,123		(504,733	)	16		3,390
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(724,523	)	(43,907	)	(16	)	(768,433	)
June 30, 2017	8,372,150		1,686,231		—		10,058,378
Proved developed reserves:
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
June 30, 2017	6,617,389		1,332,803		—		7,950,192
Proved undeveloped reserves:
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
June 30, 2017	1,754,761		353,425		—		2,108,186

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, 2017, 2016, and 2015 are as follows:



	For the Years Ended June 30,
	2017			2016			2015
Future cash inflows	$	425,094,736		$	383,491,193		$	807,030,282
Future production costs and severance taxes	(213,115,443		)	(179,182,565		)	(309,225,333		)
Future development costs	(22,631,856		)	(16,595,047		)	(49,691,006		)
Future income tax expenses	(47,055,551		)	(45,713,438		)	(123,888,665		)
Future net cash flows	142,291,886			142,000,143			324,225,278
10% annual discount for estimated timing of cash flows	(59,354,333		)	(64,042,824		)	(165,028,739		)
Standardized measure of discounted future net cash flows	$	82,937,553		$	77,957,319		$	159,196,539

Schedule of NYMEX prices used in determining future cash flows



	Year Ended June 30,
	2017			2016			2015
	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	48.85	n/a	$	42.91	n/a	$	71.88	$	3.44

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,
	2017			2016			2015
Balance, beginning of year	$	77,957,319		$	159,196,539		$	226,077,672
Net changes in sales prices and production costs related to future production	19,821,288			(120,832,747		)	(88,043,095		)
Changes in estimated future development costs	(1,626,833		)	74,991			(9,585,405		)
Sales of oil and gas produced during the period, net of production costs	(23,649,087		)	(17,079,363		)	(18,538,016		)
Net change due to extensions, discoveries, and improved recovery	—			—			—
Net change due to revisions in quantity estimates	(2,206,287		)	(18,821,014		)	(9,391,321		)
Net change due to sales of minerals in place	—			—			—
Development costs incurred during the period	2,632,547			16,327,883			7,785,095
Accretion of discount	10,086,904			21,870,650			31,974,540
Net change in discounted income taxes	(5,045,279		)	36,598,239			34,157,767
Net changes in timing of production and other	4,966,981			622,141			(15,240,698		)
Balance, end of year	$	82,937,553		$	77,957,319		$	159,196,539

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

Tabular disclosure of the future net cash flows relating to proved oil and gas reserves and oil and gas subject to purchase under long-term agreements in which the enterprise participates in the operation of the properties on which the oil and gas is located or otherwise serves as the producer. This information is presented in aggregate and for each geographic area for which reserve quantities are disclosed.

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Jun. 30, 2017

Summary of quarterly financial information

The following table presents summarized quarterly financial information for the years ended June 30, 2017 and 2016:



2017	First		Second		Third		Fourth
Revenues	$	7,593,940	$	8,529,817	$	9,525,437	$	8,835,702
Operating income	2,727,593		3,675,381		3,893,236		2,583,912
Net income available to common shareholders	$	563,345	$	2,307,634	$	2,419,143	$	1,500,761
Basic and diluted net income per share	$	0.02	$	0.07	$	0.07	$	0.05

Dividends per share declared and paid in the quarter	$	0.05	$	0.065	$	0.070	$	0.070



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 and diluted net income (loss) per share	$	0.09	$	0.02		$	(0.01	)	$	0.63

Dividends per share declared and paid in the quarter	$	0.05	$	0.05		$	0.05		$	0.05

(1) Includes $1.3 million restructuring charge.

(2) Includes gain on settlement of Delhi field litigation of $28.1 million.

Summary of Significant Accounting Policies (Details)	12 Months Ended
Summary of Significant Accounting Policies (Details)	Jun. 30, 2017 USD ($)
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
Income tax expense
Other Property and Equipment
Excess tax deficiency from share-based compensation	$ 27,884

Dehli Field Litigation Settlement (Details) - USD ($)			12 Months Ended
Dehli Field Litigation Settlement (Details) - USD ($)	Jul. 01, 2016	Jun. 24, 2016	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Loss Contingencies [Line Items]
Delhi field litigation settlement gain			$ 0	$ 28,096,500	$ 0
Fair value of litigation settlement			0	$ 596,500	$ 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
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) - USD ($)	Jun. 30, 2017	Jun. 30, 2016
Receivables [Abstract]
Receivables from oil and gas sales	$ 2,722,880	$ 2,637,593
Other	3,822	595
Total receivables	$ 2,726,702	$ 2,638,188

Prepaid Expenses and Other Current Assets (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 169,416	$ 168,681
Prepaid federal and state income taxes	121,232	0
Retainers and deposits	7,553	30,568
Derivative assets, net	0	14,132
Other prepaid expenses	89,471	52,500
Prepaid expenses and other current assets	$ 387,672	$ 265,881

Property and Equipment - Summary of Property and Equipment (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016
Oil and natural gas properties
Property costs subject to amortization	$ 84,962,933	$ 77,408,353
Less: Accumulated depreciation, depletion, and amortization	(23,172,865)	(17,437,890)
Unproved properties not subject to amortization	0	0
Oil and natural gas properties, net	61,790,068	59,970,463
Other property and equipment
Furniture, fixtures, office equipment and other, at cost	135,377	235,752
Less: Accumulated depreciation	(94,688)	(207,103)
Other property and equipment, net	$ 40,689	$ 28,649

Property and Equipment - Narrative (Details) $ in Millions	12 Months Ended
Property and Equipment - Narrative (Details) $ in Millions	Jun. 30, 2017 USD ($)
Delhi Field
Property, Plant and Equipment [Line Items]
Capital expenditures	$ 7.1
NGL Plant Project
Property, Plant and Equipment [Line Items]
Capital expenditures	4.8
Incurred costs on a cumulative basis	$ 26.3

Other Assets (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Royalty rights	$ 108,512	$ 108,512
Less: Accumulated amortization of royalty rights	(20,346)	(6,782)
Investment in Well Lift Inc., at cost	108,750	108,750
Deferred loan costs	168,972	168,972
Less: Accumulated amortization of deferred loan costs	(70,504)	(13,963)
Other assets, net	$ 295,384	$ 365,489

Other Assets - Additional Information (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015	Apr. 30, 2016
Line of Credit Facility [Line Items]
Unamortized debt issuance costs	$ 98,468
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	$ 56,541	$ 46,374	$ 48,636

Restructuring - Investments in Well Lift Inc (Details)	1 Months Ended	3 Months Ended		6 Months Ended	12 Months Ended
Restructuring - Investments in Well Lift Inc (Details)	Dec. 31, 2015 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) employee	Dec. 31, 2015 USD ($)	Jun. 30, 2017 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
Schedule of Cost-method Investments [Line Items]
Investment in Well Lift Inc., at cost					$ 108,750	$ 108,750
Restructuring charges (income)		$ 1,300,000			4,488	1,257,433	$ (5,431)
Stock-based compensation					1,180,618	$ 1,809,548	$ 943,653
GARP
Schedule of Cost-method Investments [Line Items]
Number of employees terminated \| employee			3
Restructuring charges (income)				$ 688,205
Restructuring Reserve	$ 628,866		$ 628,866	628,866
Adjustment to cost					$ 4,488
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

Accrued Liabilities and Other - Schedule of Other Current Liabilities (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016
Other Liabilities Disclosure [Abstract]
Accrued incentive and other compensation	$ 413,113	$ 999,172
Accrued restructuring charges	0	419,488
Asset retirement obligations due within one year	35,115	201,896
Accrued royalties, including suspended accounts	17,708	49,580
Accrued franchise taxes	150,062	62,834
Payable for settled derivatives	0	318,708
Accrued - other	1,841	46,273
Accrued liabilities and other	$ 617,839	$ 2,097,951

Asset Retirement Obligations - Summary of Asset Retirement Obligations (Details) - USD ($)

12 Months Ended

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2015

Reconciliation of the beginning and ending asset retirement obligation

Asset retirement obligations—beginning of period

$ 962,196

^[1]

$ 772,990

Liabilities incurred

52,792

28,505

Liabilities settled

(157,164)

Liabilities sold

^[1]

(47,817)

Accretion of discount

59,664

49,054

$ 34,866

Revisions to previous estimates

419,072

111,647

Asset retirement obligations — end of period

1,288,743

^[1]

962,196

^[1]

$ 772,990

Less current asset retirement obligations

(35,115)

(201,896)

Long-term portion of asset retirement obligations

$ 1,253,628

$ 760,300

[1]	As we have now retired all of our remaining operated wells, our asset retirement obligations as of June 30, 2017 consist entirely of our working interest obligations in the Delhi field.

Stockholders' Equity - Narrative (Details)

1 Months Ended

3 Months Ended

12 Months Ended

Nov. 14, 2016

USD ($)

Sep. 30, 2016

USD ($)

$ / shares

Dec. 31, 2016

$ / shares

Dec. 31, 2013

$ / shares

Jun. 30, 2017

$ / shares

Mar. 31, 2017

$ / shares

Dec. 31, 2016

$ / shares

Sep. 30, 2016

USD ($)

$ / shares

Jun. 30, 2016

$ / shares

Mar. 31, 2016

$ / shares

Dec. 31, 2015

$ / shares

^[2]

Sep. 30, 2015

$ / shares

Mar. 31, 2015

$ / shares

Jun. 30, 2017

USD ($)

increase

$ / shares

Jun. 30, 2016

USD ($)

$ / shares

Jun. 30, 2015

USD ($)

$ / shares

May 31, 2015

USD ($)

Common stock, outstanding shares (in shares) | shares

33,087,308

32,907,863

33,087,308

32,907,863

Cash dividends paid (per common share) | $ / shares

$ 0.065

$ 0.10

$ 0.07

$ 0.065

$ 0.05

^[1]

$ 0.05

Number of increases to quarterly cash dividend | increase

Cash dividends paid to common stockholders

$ 8,432,435

$ 6,565,823

$ 9,833,642

Redemption of preferred shares

7,932,975

Cash dividends to preferred stockholders

$ 250,990

$ 674,302

Series A Cumulative Preferred Stock

Preferred stock dividend rate (as a percent)

8.50%

Preferred stock, liquidation preference (in dollars per share) | $ / shares

$ 25.00

Common Stock

Purchases of treasury stock (in shares) | shares

83,675

16,292

7,535

Treasury stock acquired, average cost (in dollars per share) | $ / shares

$ 6.42

$ 5.49

$ 9.16

Purchases of treasury stock

$ 537,014

$ 89,503

$ 69,015

Percentage of cash dividends treated as qualified dividend income

14.00%

Percentage of cash dividends treated as return of capital

86.00%

Preferred

Percentage of cash dividends treated as qualified dividend income

100.00%

Preferred | Series A Cumulative Preferred Stock

Issuance of preferred stock (in shares) | shares

317,319

Preferred stock dividend rate (as a percent)

8.50%

Preferred stock, liquidation preference (in dollars per share) | $ / shares

$ 25.00

Redemption of preferred shares

$ 7,932,975

Preferred stock deemed dividend

$ 1,002,440

Cash dividends to preferred stockholders

$ 250,990

$ 674,302

2015 Share Repurchase Program | Common Stock

Amount authorized to be repurchased

$ 5,000,000

Purchases of treasury stock (in shares) | shares

265,762

202,390

63,372

Treasury stock acquired, average cost (in dollars per share) | $ / shares

$ 6.05

$ 5.80

$ 6.87

Purchases of treasury stock

$ 1,609,008

$ 1,173,899

$ 435,109

[1]	Includes gain on settlement of Delhi field litigation of $28.1 million.
[2]	Includes $1.3 million restructuring charge.

Stock-Based Compensation - Narrative (Details) - USD ($)		12 Months Ended
	Aug. 27, 2014	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015	Dec. 08, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise of stock options (shares)		35,231	50,000	87,000
Stock options intrinsic value		$ 188,821	$ 131,000	$ 501,810
Restructuring Charges
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-cash stock-based compensation expense			$ 59,339
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vested (in shares)		0	0	0
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock, vested (shares)		210,737	86,719	91,306
Restricted stock, vested in period, grant date fair value (in dollars per share)		$ 1,520,569	$ 757,229	$ 766,970
Non-cash stock-based compensation expense		$ 1,180,618	$ 1,809,548	$ 943,653
Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		2 years 9 months 29 days	3 years 303 days
Fair value at grant date, per share (in dollars per share)		$ 5.44
Shares granted (in shares)		54,475
Restricted Stock, Market Based \| Minimum
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)		$ 3.42	$ 2.93	$ 4.26
Restricted Stock, Market Based \| Maximum
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)		$ 5.62	$ 5.07	$ 8.40
2016 Equity Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for granting (shares)					1,100,000
Shares available for grant (shares)		1,100,000
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)		0			32,146
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 \| 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 \| Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		4 years

Stock-Based Compensation - Schedule of Options and Incentive Warrants (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Number of Stock Options
Stock Options Outstanding, Beginning of Period (in shares)	35,231
Stock Options , Exercises (in shares)	(35,231)	(50,000)	(87,000)
Stock Options Outstanding, End of Period (in shares)	0	35,231
Weighted Average Exercise Price
Stock Options Outstanding, Weighted Average Exercise Price, Beginning of Period (in USD per share)	$ 2.19
Stock Options, Exercises, Weighted Average Exercise Price (in USD per share)	2.19
Stock Options Outstanding, Weighted Average Exercise Price, End of Period (in USD per share)	$ 0.00	$ 2.19
Aggregate Intrinsic Value
Stock Options, Outstanding, Aggregate Intrinsic Value	$ 0
Stock Options, Outstanding, Weighted Average Remaining Contractual Term (in years)	0 years

Stock-Based Compensation - Schedule of Restricted Stock (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Restricted Stock
Number of Restricted Shares
Nonvested, beginning of period (shares)	406,848
Vested (shares)	(210,737)	(86,719)	(91,306)
Nonvested, end of period (shares)	391,624	406,848
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, beginning of period (in USD per share)	$ 6.74
Vested, weighted average grant date fair value (in USD per share)	7.22
Weighted average grant date fair value, end of period (in USD per share)	$ 6.22	$ 6.74
Unamortized compensation expense	$ 1,648,297	$ 0
Weighted Average Remaining Amortization Period (in years)	2 years
Restricted Stock, Service Based
Number of Restricted Shares
Grants (shares)	86,563
Nonvested, end of period (shares)	217,922
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)	$ 7.02
Weighted average grant date fair value, end of period (in USD per share)	$ 7.03
Restricted Stock, Performance Based
Number of Restricted Shares
Grants (shares)	54,475
Nonvested, end of period (shares)	54,475
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)	$ 5.67
Weighted average grant date fair value, end of period (in USD per share)	$ 5.67
Restricted Stock, Market Based
Number of Restricted Shares
Grants (shares)	54,475
Nonvested, end of period (shares)	119,227
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)	$ 5.44
Weighted average grant date fair value, end of period (in USD per share)	$ 4.97

Stock-Based Compensation - Schedule of Contingent Restricted Stock (Details)

12 Months Ended

Jun. 30, 2017

USD ($)

$ / shares

Contingent Restricted Stock Grants

Number of Restricted Stock Units

Nonvested, beginning of period (shares) | shares

91,172

Vested (shares) | shares

(32,376)

Nonvested, end of period (shares) | shares

113,270

Weighted Average Grant-Date Fair Value

Weighted average grant date fair value, beginning of period (in USD per share) | $ / shares

$ 5.21

Vested, weighted average grant date fair value (in USD per share) | $ / shares

6.09

Weighted average grant date fair value, end of period (in USD per share) | $ / shares

$ 4.64

Unamortized compensation expense | $

$ 121,668

^[1]

Weighted Average Remaining Amortization Period (in years)

2 years 1 month 6 days

Contingent Restricted Stock, Performance Based

Number of Restricted Stock Units

Grants (shares) | shares

27,237

Nonvested, end of period (shares) | shares

39,403

Weighted Average Grant-Date Fair Value

Grants, weighted average grant date fair value (in USD per share) | $ / shares

$ 5.67

Weighted average grant date fair value, end of period (in USD per share) | $ / shares

$ 7.02

Potential future compensation expense | $

$ 276,702

Contingent Restricted Stock, Market Based

Number of Restricted Stock Units

Grants (shares) | shares

27,237

Nonvested, end of period (shares) | shares

73,867

Weighted Average Grant-Date Fair Value

Grants, weighted average grant date fair value (in USD per share) | $ / shares

$ 3.42

Weighted average grant date fair value, end of period (in USD per share) | $ / shares

$ 3.37

[1]	Excludes $276,702 of potential future compensation expense for 39,403 shares of performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Supplemental Disclosure of Cash Flow Information - Schedule of Supplement Cash Flow (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Supplemental Cash Flow Elements [Abstract]
Income taxes paid	$ 1,495,377	$ 540,000	$ 220,000
Income tax refunds	0	1,556,999	331,733
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	(3,076,245)	(2,250,048)	5,422,566
Deferred loan costs charged to oil and gas property costs	0	107,196	0
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	471,864	140,151	576,039
Mengel working interest acquired in Delhi Field litigation settlement	0	596,500	0
Royalty rights acquired through non-monetary exchange of patent and trademark assets	0	108,512	0
Previously acquired Company shares swapped by holders to pay stock option exercise price	77,156	76,500	0
Accrued purchases of treasury stock	$ 0	$ (170,283)	$ 170,283

Income Taxes - Narrative (Details) - USD ($)	1 Months Ended	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Sep. 30, 2015	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Operating Loss Carryforwards [Line Items]
Unrecognized tax benefits		$ 0	$ 0	$ 0
Accrued interest and penalties		$ 0	$ 0	$ 0
Income tax provision computed at the statutory federal rate		34.00%	34.00%	34.00%
Deferred tax asset		$ 0	$ 105,321	$ 82,414
Deferred income taxes		15,826,291	11,840,693	11,242,551
Tax loss carryforwards from exercise of options and warrants			25,300,000
Tax benefits related to stock-based compensation		0	$ 9,650,657	$ 1,633,946
Net loss for state tax purposes	$ 19,100,000
Mineral Property Depletion
Operating Loss Carryforwards [Line Items]
Depletion carryforward		7,200,000
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]
Net operating loss		$ 9,100,000
Income tax refund	1,500,000
Interest on refund recorded as a deduction of current income tax expense	$ 57,467

Income Taxes - Components of Income Tax Provision (Benefit) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Current:
Federal	$ 168,152	$ 8,731,290	$ 1,413,296
State	581,593	264,254	608,436
Total current income tax provision	749,745	8,995,544	2,021,732
Deferred:
Federal	3,880,522	541,891	1,282,059
State	210,397	33,344	140,430
Total deferred income tax provision	4,090,919	575,235	1,422,489
Total income tax provision	$ 4,840,664	$ 9,570,779	$ 3,444,221

Income Taxes - Reconciliation of Statutory and Income Tax Expense (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax provision computed at the statutory federal rate	$ 4,380,892	$ 11,638,588	$ 2,868,267
Depletion in excess of basis	(92,196)	(2,242,620)	0
State income taxes, net of federal tax benefit	522,713	196,415	595,708
Permanent differences related to stock-based compensation	27,884	0	0
Other	1,371	(21,604)	(19,754)
Total income tax provision	$ 4,840,664	$ 9,570,779	$ 3,444,221
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Income tax provision computed at the statutory federal rate	34.00%	34.00%	34.00%
Depletion in excess of basis	(0.70%)	(6.60%)	0.00%
State income taxes, net of federal tax benefit	4.10%	0.60%	7.10%
Permanent differences related to stock-based compensation	0.20%	0.00%	0.00%
Other	0.00%	(0.10%)	(0.20%)
Income tax provision	37.60%	27.90%	40.90%

Income Taxes - Schedule of Deferred Income Taxes (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Deferred tax assets:
Non-qualified stock-based compensation	$ 367,159	$ 553,182	$ 173,647
Net operating loss carry-forwards	852,477	386,808	400,288
AMT credit carry-forward	110,564	0	701,254
Other	18,581	130,947	91,113
Gross deferred tax assets	1,348,781	1,070,937	1,366,302
Valuation allowance	(292,446)	(292,446)	(292,446)
Total deferred tax assets	1,056,335	778,491	1,073,856
Deferred tax liability:
Oil and natural gas properties	(16,882,626)	(12,513,863)	(12,233,993)
Total deferred tax liability	(16,882,626)	(12,513,863)	(12,233,993)
Net deferred tax liability	$ (15,826,291)	$ (11,735,372)	$ (11,160,137)

Income Taxes - Balance Sheet Items (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Current deferred tax asset	$ 0	$ 105,321	$ 82,414
Non-current deferred tax liability	15,826,291	11,840,693	11,242,551
Net liability	$ 15,826,291	$ 11,735,372	$ 11,160,137

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

Net Income Per Share - Schedule of Basic and Diluted Earnings (Loss) Per Share (Details) - USD ($)

3 Months Ended

12 Months Ended

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

^[1]

Mar. 31, 2016

Dec. 31, 2015

^[2]

Sep. 30, 2015

Jun. 30, 2017

Jun. 30, 2016

Jun. 30, 2015

Numerator

Net income attributable to common shareholders

$ 1,500,761

$ 2,419,143

$ 2,307,634

$ 563,345

$ 20,705,894

$ (298,183)

$ 654,697

$ 2,923,652

$ 6,790,883

$ 23,986,060

$ 4,317,555

Denominator

Weighted average number of common shares—Basic (in shares)

33,034,480

32,810,375

32,817,456

Effect of dilutive securities:

Total weighted average dilutive securities (in shares)

76,080

50,856

106,562

Weighted average number of common shares and dilutive potential common shares used in diluted EPS (in shares)

33,110,560

32,861,231

32,924,018

Net income per common share - Basic (in dollars per share)

$ 0.21

$ 0.73

$ 0.13

Net income per common share - Diluted (in dollars per share)

$ 0.21

$ 0.73

$ 0.13

Contingent restricted stock grants

Effect of dilutive securities:

Weighted average dilutive securities (in shares)

53,546

9,378

4,422

Stock Options

Effect of dilutive securities:

Weighted average dilutive securities (in shares)

22,534

41,478

102,140

[1]	Includes gain on settlement of Delhi field litigation of $28.1 million.
[2]	Includes $1.3 million restructuring charge.

Net Income Per Share - Schedule of Outstanding Potentially Dilutive Securities (Details) - $ / shares	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
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)	$ 0.00	$ 0.00	$ 0.00
Outstanding (in shares)	113,270	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
Outstanding (in shares)		35,231	91,061

Credit Agreements (Details)	Apr. 11, 2016 USD ($)	Feb. 29, 2012 USD ($)	Jun. 30, 2017 USD ($)	Apr. 30, 2016 USD ($)
Debt Instrument [Line Items]
Unamortized debt issuance costs			$ 98,468
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
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
Outstanding borrowings			$ 0
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 - Schedule of Future Minimum Lease Commitments (Details)	Jun. 30, 2017 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2018	$ 73,073
2019	66,984
Total	$ 140,057

Commitments and Contingencies - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Rent expense	$ 80,472	$ 182,626	$ 175,103

Concentrations of Credit Risk - Schedule of Credit Risk (Details) - Net revenue - Major Customers	12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Concentrations of Credit Risk
Percent of Total Revenue	100.00%	100.00%	100.00%
Plains Marketing L.P. (Oil sales from Delhi)
Concentrations of Credit Risk
Percent of Total Revenue	97.00%	99.00%	99.00%
American Midstream Gas Solutions (NGL sales from Delhi)
Concentrations of Credit Risk
Percent of Total Revenue	3.00%	0.00%	0.00%
All others
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	1.00%	1.00%

Retirement Plan (Details) - USD ($)	12 Months Ended
Retirement Plan (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Retirement Benefits [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	$ 53,113	$ 88,348	$ 85,676

Derivatives (Details) - USD ($)	12 Months Ended
Derivatives (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net asset position of derivatives with counterparty	$ 0	$ 14,132
Gain on derivatives	29,758	3,439,229
Gain on settled derivatives	43,890	3,315,123
Net gain (loss) on unsettled derivatives	(14,132)	124,106
Loss on derivative instruments, net	$ (29,758)	$ (3,439,229)	$ 109,974

Fair Value Measurement (Details) - Level 2	Jun. 30, 2017 USD ($)
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 about Oil and Natural Gas Producing Properties (unaudited) - Narrative (Details)

12 Months Ended

Jun. 24, 2016

USD ($)

Jun. 30, 2017

USD ($)

Mcf

bbl

Jun. 30, 2016

USD ($)

Mcf

bbl

Jun. 30, 2015

USD ($)

Mcf

bbl

Oil and natural gas property costs attributable to the recognition of asset retirement obligations | $

$ 471,864

$ 140,151

$ 576,039

Fair value of litigation settlement | $

$ 0

$ 596,500

$ 0

Period Considered for Unweighted Arithmetic Average for Determining Reserve Volumes and Values

12 months

Period Considered for Determining Unweighted Arithmetic Average of First Day of Month, Commodity Prices

12 months

Natural Gas

Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf

^[1]

(3,319)

^[2]

(2,894,703)

^[3]

Natural Gas Liquids

Revision increase(decrease) of previous estimates (in Bbls/Mcf) | bbl

(504,733)

^[1]

(198,233)

^[2]

156,195

^[3]

Revision due to improved design (in Bbls/Mcf) | bbl

185,499

Delhi Field | Natural Gas

Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf

(2,246,524)

Giddings Field | Natural Gas

Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf

(452,786)

Giddings Field | Natural Gas Liquids

Revision increase(decrease) of previous estimates (in Bbls/Mcf) | bbl

(29,304)

Dehli Field Litigation | Denbury Resources, Inc