View Filing Data

Depreciation, depletion and amortization

$ 41,281,212

$ 34,484,896

$ 26,349,502

Operating costs

6,011,998

5,719,405

5,165,120

Accretion of discount on asset retirement obligations

90,290

59,664

49,054

General and administrative expenses

^[1]

6,773,781

4,985,408

9,079,597

Restructuring charges

4,488

1,257,433

Total operating costs

25,069,571

21,604,774

24,684,315

Income from operations

16,211,641

12,880,122

1,665,187

Other

Gain on settled derivative instruments, net

43,890

3,315,123

Gain (loss) on unsettled derivative instruments, net

(14,132)

124,106

Delhi field litigation settlement

28,096,500

Delhi field insurance recovery related to pre-reversion event

1,074,957

Interest and other income

85,654

56,855

26,211

Interest (expense)

(110,780)

(81,758)

(70,943)

Income before income tax provision

16,186,515

12,884,977

34,231,141

Income tax provision (benefit)

(3,431,969)

4,840,664

9,570,779

Net income attributable to the Company

19,618,484

8,044,313

24,660,362

Dividends on preferred stock

250,990

674,302

Deemed dividend on redeemed preferred shares

1,002,440

Net income attributable to common shareholders

$ 19,618,484

$ 6,790,883

$ 23,986,060

Earnings per common share

Basic (in dollars per share)

$ 0.59

$ 0.21

$ 0.73

Diluted (in dollars per share)

$ 0.59

$ 0.21

$ 0.73

Weighted average number of common shares outstanding

Basic (in shares)

33,126,469

33,034,480

32,810,375

Diluted (in shares)

33,178,535

33,110,560

32,861,231

Crude Oil

Revenues

$ 38,153,417

$ 33,550,698

$ 26,130,762

Natural Gas Liquids

Revenues

3,127,795

934,202

7,885

Natural Gas

Revenues

Artificial Lift Technology

(4)

2,895

Revenues

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

207,960

Operating costs

Production costs

70,932

Production

Operating costs

Production costs

$ 12,193,502

$ 10,835,809

$ 9,062,179

[1]	General and administrative expenses for the years ended June 30, 2018, 2017 and 2016 included non-cash stock-based compensation expense of $1,366,764, $1,180,618, and $1,750,209, respectively.

Consolidated Statements of Operations (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Non-cash stock-based compensation expense	$ 1,366,764	$ 1,180,618	$ 1,809,548
General and Administrative Expense
Non-cash stock-based compensation expense	$ 1,366,764	$ 1,180,618	$ 1,750,209

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
Consolidated Statements of Cash Flows - USD ($)	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Cash Flows From Operating Activities
Net income attributable to the Company	$ 19,618,484	$ 8,044,313	$ 24,660,362
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	6,068,265	5,775,946	5,211,494
Impairments included in restructuring charge	0	0	569,228
Stock-based compensation	1,366,764	1,180,618	1,809,548
Accretion of discount on asset retirement obligations	90,290	59,664	49,054
Settlement of asset retirement obligations	0	(157,910)	0
Deferred income taxes	(5,270,856)	4,090,919	575,235
Gain on derivative instruments, net	0	(29,758)	(3,439,229)
Noncash gain on Delhi field litigation settlement	0	0	(596,500)
Write-off of deferred loan costs	0	0	50,414
Changes in operating assets and liabilities:
Receivables	(1,215,214)	(88,514)	484,285
Prepaid expenses and other current assets	(136,835)	(135,923)	24,754
Accounts payable and accrued expenses	(107,081)	(1,626,648)	822,730
Income taxes payable	122,760	(621,850)	431,818
Net cash provided by operating activities	20,536,577	16,490,857	30,653,193
Cash flows from investing activities
Derivative settlements received (paid)	0	(272,318)	3,633,831
Development of oil and natural gas properties	(3,690,845)	(10,158,960)	(21,095,901)
Capital expenditures for other property and equipment	(7,846)	(32,260)	(6,883)
Other assets	(19,282)	0	(161,345)
Net cash used by investing activities	(3,717,973)	(10,463,538)	(17,630,298)
Cash flows from financing activities
Proceeds from the exercise of stock options	0	0	51,000
Common share repurchases, including shares surrendered for tax withholding	(571,083)	(459,858)	(1,357,185)
Common stock dividends paid	(11,594,541)	(8,432,435)	(6,565,823)
Preferred stock dividends paid	0	(250,990)	(674,302)
Redemption of preferred shares	0	(7,932,975)	0
Deferred loan costs	0	0	(168,972)
Tax benefits related to stock-based compensation	0	0	9,650,657
Other	0	32	33
Net cash provided (used) by financing activities	(12,165,624)	(17,076,226)	935,408
Net increase (decrease) in cash, cash equivalents and restricted cash	4,652,980	(11,048,907)	13,958,303
Cash, cash equivalents and restricted cash, beginning of year	23,028,153	34,077,060	20,118,757
Cash, cash equivalents and restricted cash, end of year	$ 27,681,133	$ 23,028,153	$ 34,077,060

Consolidated Statements of Cash Flows - Supplemental Information - USD ($)	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Statement of Cash Flows [Abstract]
Cash and cash equivalents	$ 24,929,844	$ 23,028,153	$ 34,077,060
Restricted cash included in current assets	2,751,289	0	0
Total cash, cash equivalents and restricted cash shown in the statements of cash flows	$ 27,681,133	$ 23,028,153	$ 34,077,060

Consolidated Statements of Changes in Stockholders' Equity - USD ($)	Total	Preferred	Common Stock	Additional Paid-in Capital	Retained Earnings	Treasury Stock
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	127,500		$ 50	127,450
Exercise of stock options (shares)			50,000
Forfeiture of restricted stock			$ (41)	41
Forfeiture of restricted stock (shares)			(40,758)
Common share repurchases, including shares surrendered for tax withholding	(1,263,402)					(1,263,402)
Common share repurchases, including shares surrendered for tax withholding (shares)			(218,682)
Retirements of treasury stock			$ (219)	(1,263,183)		1,263,402
Stock-based compensation	1,809,548			1,809,548
Tax benefits related to stock-based compensation	9,650,657			9,650,657
Net income	24,660,362				24,660,362
Common stock cash dividends	(6,565,823)				(6,565,823)
Preferred stock cash dividends	(674,302)				(674,302)
Balance at Jun. 30, 2016	76,321,150	$ 317	$ 32,907	47,171,563	29,116,363	0
Balance (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	$ 77,156		$ 35	77,121
Exercise of stock options (shares)	35,231		35,231
Common share repurchases, including shares surrendered for tax withholding	$ (537,014)					(537,014)
Common share repurchases, including shares surrendered for tax withholding (shares)			(83,675)
Retirements of treasury stock			$ (83)	(536,931)		537,014
Stock-based compensation	1,180,618			1,180,618
Redemption of preferred shares	(7,932,975)	$ (317)		(6,930,218)	(1,002,440)
Redemption of preferred shares (shares)		(317,319)
Net income	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
Increase (Decrease) in Stockholders' Equity
Issuance of restricted common stock	0		$ 183	(183)
Issuance of restricted common stock (shares)			183,537
Forfeiture of restricted stock			$ (117)	117
Forfeiture of restricted stock (shares)			(117,094)
Common share repurchases, including shares surrendered for tax withholding	(571,083)					(571,083)
Common share repurchases, including shares surrendered for tax withholding (shares)			(73,208)
Retirements of treasury stock			$ (73)	(571,010)		571,083
Stock-based compensation	1,366,764			1,366,764
Net income	19,618,484				19,618,484
Common stock cash dividends	(11,594,541)				(11,594,541)
Balance at Jun. 30, 2018	$ 77,289,479	$ 0	$ 33,080	$ 41,757,645	$ 35,498,754	$ 0
Balance (shares) at Jun. 30, 2018		0	33,080,543

Organization and Basis of Preparation	12 Months Ended
Organization and Basis of Preparation	Jun. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Preparation	Organization and Basis of Preparation Nature of Operations. Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management and development of producing oil and gas properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement and other exploitation efforts on its properties. Our largest active investment is our interest in a CO₂ enhanced oil recovery project in Louisiana's Delhi field. 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 of prior periods 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. 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, 2018
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. Restricted Cash. Funds legally designated for a specified purpose are classified as restricted cash. Such a balance is classified on the statement of financial position as either current or non-current depending on its expected use. Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist 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 receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2018 and 2017, no allowance for doubtful accounts was considered necessary. Oil and Natural Gas Properties. We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized. Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent, and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; and 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, 2018, 2017 or 2016. Other Property and Equipment. Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture and office equipment. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method. 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, restricted cash, 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 have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues. Derivative Instruments. The Company has used and may continue to use derivative transactions to reduce its exposure to oil, natural gas or NGL 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 ("DD&A"). 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 building improvements, office and computer 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 largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense. Earnings (Loss) Per Share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss 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. Recently Adopted Accounting Pronouncements. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. The Company retrospectively early adopted this guidance on April 1, 2018. ASU 2016-18 had no impact on the consolidated statements of cash flows for the previously reported interim periods of our current fiscal year and for prior fiscal year consolidated statements of cash flows presented in this annual report on Form 10-K. New Accounting Pronouncements Not Yet Adopted. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which will supersede most of the existing revenue recognition standards and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The update was issued to increase stakeholders’ awareness of the proposals for technical corrections and to expedite improvements. The Company will adopt these updates effective July 1, 2018, using the full retrospective approach, meaning any cumulative effect of initially applying the standard is recognized in the earliest period presented in the financial statements. The Company has finalized the detailed analysis of its contracts and of the impact of the standard on its contracts and found that there was no significant impact on its financial position or results of operations. Upon adoption of this standard, the Company will not be required to record a cumulative effect adjustment as the new standard does not have a quantitative impact on net income compared to existing generally accepted accounting principles. Also, upon adoption of the standard, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the new updates will have a material change on how it presents information regarding its revenue streams as compared to existing generally accepted accounting principles although certain revenue streams under the new standard will be presented on a net rather than gross basis. 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 investees) 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, 2018. 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. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“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. The Company will retrospectively adopt ASU 2016-15 on July 1, 2018, and does not expect its adoption to have a material effect on its consolidated statements of cash flows. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will adopt ASU 2017-01 effective July 1, 2018 on a prospective basis.

Enduro Purchase and Sale Agreement and Related Subsequent Events	12 Months Ended
	Jun. 30, 2018
Asset Acquisition [Abstract]
Enduro Purchase and Sale Agreement and Related Subsequent Events	Enduro Purchase and Sale Agreement and Related Subsequent Events As previously disclosed, the Company entered into a Purchase and Sale Agreement ("PSA") on May 15, 2018, to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million, subject to the outcome of Enduro's Chapter 11 process. Contemporaneous with executing the PSA, the Company made a $2.75 million deposit to an acquisition escrow account which is reflected in restricted cash together with earned interest on the Company's June 30, 2018 statement of financial position. On July 20, 2018, the Company was repaid its deposit together with related earned interest as a higher bidder emerged in the Chapter 11 bidding process. The Company's initial and subsequent bids represented offers under Section 363 of the U.S. Bankruptcy Code in connection with the Chapter 11 filing of Enduro and certain of its affiliates. Such offers are commonly referred to as “stalking horse” bids and are subject to higher bids, in accordance with the bidding procedures approved by the Bankruptcy Court. The PSA provided the Company with certain important protections in this process, including return of the escrowed deposit and payment to the Company of a $1.1 million break-up fee upon the closing of a higher bidder's purchase transaction. In connection with the PSA, the Company incurred third party due diligence expenses of $0.4 million, which were reflected in the Company's consolidated statement of operations for the year ended June 30, 2018. The full amount of the break-up fee was paid in late August 2018.

Prepaid Expenses and Other Current Assets

12 Months Ended

Jun. 30, 2018

Prepaid Expenses and Other Current Assets

As of June 30, 2018 and June 30, 2017 our prepaid expenses and other current assets consisted of the following:



	June 30, 2018		June 30, 2017
Prepaid insurance	$	198,558	$	169,416
Prepaid federal and state income taxes	231,920		121,232
Retainers and deposits	11,089		7,553
Other prepaid expenses	82,940		89,471
Prepaid expenses and other current assets	$	524,507	$	387,672

Receivables

12 Months Ended

Jun. 30, 2018

Receivables [Abstract]

Receivables

As of June 30, 2018 and June 30, 2017 our receivables consisted of the following:



	June 30, 2018		June 30, 2017
Receivables from oil and gas sales	$	3,940,998	$	2,722,880
Other	918		3,822
Total receivables	$	3,941,916	$	2,726,702

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.

Property, Plant and Equipment [Abstract]

Property and Equipment

12 Months Ended

Jun. 30, 2018

Property and Equipment

As of June 30, 2018 and June 30, 2017, our oil and natural gas properties and other property and equipment consisted of the following:



	June 30, 2018			June 30, 2017
Oil and natural gas properties:
Property costs subject to amortization	$	90,392,918		$	84,962,933
Less: Accumulated depreciation, depletion, and amortization	(29,153,172		)	(23,172,865		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	61,239,746			61,790,068
Other property and equipment:
Furniture, fixtures and office equipment, at cost	143,223			135,377
Less: Accumulated depreciation	(112,816		)	(94,688		)
Other property and equipment, net	$	30,407		$	40,689

As of June 30, 2018 and 2017, all oil and gas property costs were being amortized.

During the years ended June 30, 2018 and 2017, the Company incurred capital expenditures of $5.4 million and $7.1 million, respectively, in the Delhi field.

Other Assets

12 Months Ended

Jun. 30, 2018

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

Other Assets

As of June 30, 2018 and June 30, 2017 our other assets consisted of the following:



	June 30, 2018			June 30, 2017
Royalty rights	108,512			108,512
Less: Accumulated amortization of royalty rights	(33,910		)	(20,346		)
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	(126,771		)	(70,504		)
Software license	20,662			—
Less: Accumulated amortization of software license	(1,380		)	—
Other assets, net	$	244,835		$	295,384

Our royalty rights and investment in Well Lift, Inc. ("WLI") resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual property to WLI and retained a 5% royalty on future gross revenues associated the technology. We own 17.5% of the common stock of WLI and account for our investment under the cost method. Any dividends paid are recorded as income and any return of capital reduces our cost basis in the investment. Our investment in WLI is evaluated for impairment at least quarterly or when management identifies any events or changes in circumstances that might 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. 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.

Accrued Liabilities and Other

12 Months Ended

Jun. 30, 2018

Other Liabilities Disclosure [Abstract]

Accrued Liabilities and Other

As of June 30, 2018 and June 30, 2017 our accrued liabilities and other consisted of the following:



	June 30, 2018		June 30, 2017
Accrued incentive and other compensation	$	415,182	$	413,113
Accrued severance (for two former employees)	160,089		—
Asset retirement obligations due within one year	35,539		35,115
Accrued royalties, including suspended accounts	11,498		17,708
Accrued franchise taxes	162,805		150,062
Accrued ad valorem taxes	89,773		108,641
Accrued liabilities and other	$	874,886	$	724,639

Asset Retirement Obligations

12 Months Ended

Jun. 30, 2018

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, 2018 and 2017:



	Years Ended
	2018			2017
Asset retirement obligations — beginning of period	$	1,288,743		$	962,196
Liabilities incurred	44,700			52,792
Liabilities settled	—			(157,164		)
Liabilities sold	—			(47,817		)
Accretion of discount	90,290			59,664
Revisions to previous estimates	(778		)	419,072
Asset retirement obligations — end of period	1,422,955			1,288,743
Less: current asset retirement obligations	(35,539		)	(35,115		)
Long-term portion of asset retirement obligations	$	1,387,416		$	1,253,628

Stockholders' Equity

12 Months Ended

Jun. 30, 2018

Equity [Abstract]

Stockholders' Equity

Common Stock

As of June 30, 2018, we had 33,080,543 shares of common stock outstanding.

The Company began paying quarterly cash dividends on common stock in December 2013. We paid dividends of$11,594,541, $8,432,435 and $6,565,823 from retained earnings to our common shareholders during the years ended June 30, 2018, 2017 and 2016, respectively. The following table reflects the dividends paid per common share in each quarter within the respective three fiscal years:



	Fiscal Year
	2018		2017		2016
Fourth quarter ended June 30,	$	0.100	$	0.070	$	0.050
Third quarter ended March 31,	$	0.100	$	0.070	$	0.050
Second quarter ended December 31,	$	0.075	$	0.065	$	0.050
First quarter ended September 30,	$	0.075	$	0.050	$	0.050

Repurchases of common shares are initially recorded as treasury stock, then subsequently canceled. On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Since commencement in June 2015, we have repurchased 265,762 shares at an average price of $6.05 per share, for total cost of $1,609,008. 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. The Company has also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. The following summarizes all treasury stock purchases by fiscal year:



	Fiscal Year
	2018		2017		2016
Number of treasury shares acquired	73,208		83,675		218,682
Average cost per share	$	7.80	$	6.42	$	5.78
Total cost of treasury shares acquired	$	571,083	$	537,014	$	1,263,402

Series A Cumulative Perpetual Preferred Stock

In September 2016, the Company announced the decision to redeem all 317,319 outstanding shares of its 8.5% Series A Cumulative Preferred Stock. The redemption occurred in November 2016 at the stated 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 were paid 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 prior to the November 2016 redemption date. During the year ended June 30, 2016, 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, 2018, we expect all common dividends for this fiscal year will be treated for tax purposes as qualified dividend income to the recipients. For the fiscal year ended June 30, 2017, all preferred and common dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients.

Stock-Based Incentive Plan

12 Months Ended

Jun. 30, 2018

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

Stock-Based Incentive Plan

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, 2018, 963,093 shares remained available for grant under the 2016 Plan.

At December 8, 2016, there were no shares available for future grants under the 2004 Plan. 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 outstanding grants of restricted common stock awards ("Restricted Stock") and contingent restricted common stock awards ("Contingent Restricted Stock") to employees and directors of the Company. No stock option awards that had been granted in past fiscal years remained outstanding at December 8, 2016.

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. No stock options vested during the years ended June 30, 2018, 2017, and 2016. There were no unexercised Stock Options as of June 30, 2017 and no Stock Options vested during the years ended June 30, 2018, 2017, and 2016.

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

Restricted Stock and Contingent Restricted Stock

The Company may award grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted Stock grants vest only upon the attainment of higher performance-based or market-based vesting thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock awards are reserved from the Plan under which they were granted under.

Service-based awards vest with continuous employment by the Company, generally in annual installments over a four-year period. Certain awards may contain other vesting periods, including quarterly installments and one-year vesting. Restricted Stock grants which vest based on service are valued at the fair market value on the date of grant and amortized over the service period. During the year ended June 30, 2018, we granted 136,907 service-based Restricted Stock awards, including 69,963 awards to employees and 66,944 awards to directors, most of which have a one-year vesting period. We did not grant any performance-based or market-based awards, nor any Contingent Restricted Stock awards, during this period.

Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee or director 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, 2018, certain contingent 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 vest if the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of indices consisting of peer company groups as designated from time to time by the Compensation Committee of the Board of Directors. The fair values and expected vesting periods of these awards are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. The range of assumptions used in the Monte Carlo simulation valuations for the years ended June 30, 2017 and 2016 were as follows:



	Years Ended June 30
	2017			2016
Weighted average fair value of market-based awards granted	$	4.97		$	5.50
Risk-free interest rate	1.03		%	1.46		%
Expected life in years	2.83			3.83
Expected volatility	37.8		%	34.9		%
Dividend yield	3.5		%	3.3		%

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, 2018 consisted of the following:



Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	157,906	$	7.16
Performance-based awards	21,259	5.67
Market-based awards	20,312	5.44
Unvested at June 30, 2018	199,477	$	6.83

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2018:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2018		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	391,624		$	6.22	$	—
Service-based awards granted	136,907		7.53
Vested	(211,960	)	6.73
Forfeited	(117,094	)	5.78
Unvested at June 30, 2018	199,477		$	6.83	$	747,204	2.0

The following is a summary of Restricted Stock vestings for the last three fiscal years:



	Year Ended June 30,
	2018		2017		2016
Vesting-date intrinsic value of Restricted Stock	$	1,622,937	$	1,478,478	$	485,580
Grant-date fair value of vested Restricted Stock	$	1,427,498	$	1,520,569	$	757,229

Unvested Contingent Restricted Stock awards at June 30, 2018 consisted of the following:



Award Type	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	18,406	$	7.52
Market-based awards	10,156	3.42
Unvested at June 30, 2018	28,562	$	6.06

The following table summarizes Contingent Restricted Stock activity for fiscal 2018:



	Number of Restricted Stock Units		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2018 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	113,270		$	4.64
Forfeited	(38,078	)	5.17
Vested	(46,630	)	3.34
Unvested at June 30, 2018	28,562		$	6.06	$	12,251	1.0

(1) Excludes $78,159 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

The following is a summary of Contingent Restricted Stock vestings for the last three fiscal years:



	Year Ended June 30,
	2018		2017		2016
Vest-date intrinsic value of Contingent Restricted Stock	$	347,852	$	183,572	$	—
Grant-date fair value of vested Contingent Restricted Stock	$	155,744	$	197,170	$	—

Stock-based Compensation Expense

For the years ended June 30, 2018, 2017, and 2016, we recognized stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants of $1,366,764, $1,180,618, and $1,809,548, respectively. Expense for the year ended 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, 2018

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosure of Cash Flow Information

Our supplemental disclosures of cash flow information for the years ended June 30, 2018, 2017, and 2016 are as follows:



	June 30,
	2018		2017			2016
Income taxes paid	$	1,826,754	$	1,495,377		$	540,000
Income tax refunds	—		—			1,556,999
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	1,695,218		(3,076,245		)	(2,250,048		)
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	43,922		471,864			140,151
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		)

Income Taxes

12 Months Ended

Jun. 30, 2018

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, 2018, 2017 and 2016. 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, 2015 through June 30, 2017 for federal tax purposes and for the years ended June 30, 2014 through June 30, 2017 for state tax purposes.

The components of our income tax provision (benefit) are as follows:



	June 30, 2018			June 30, 2017		June 30, 2016
Current:
Federal	$	1,186,649		$	168,152	$	8,731,290
State	652,238			581,593		264,254
Total current income tax provision	1,838,887			749,745		8,995,544
Deferred:
Federal	(5,498,890		)	3,880,522		541,891
State	228,034			210,397		33,344
Total deferred income tax provision	(5,270,856		)	4,090,919		575,235
	$	(3,431,969	)	$	4,840,664	$	9,570,779

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax provision (benefit) in our financial statements. The rate for 2018 is 27.55% due to our fiscal tax year. This is a result of the transition from the previously enacted 34% federal statutory rate to the new federal tax rate of 21%,, enacted December 31, 2017. Going forward, the federal statutory rate that will be applied is 21%. Our federal statutory rate for fiscal 2017 and 2016 was 34%. The effective tax rates for annual income tax provision (benefit) were approximately (21)%, 38% and 28% year ended June 30, 2018, 2017 and 2016, respectively. Excluding the permanent adjustment of $6.1 million benefit from the revaluation of our deferred income tax liabilities and valuation allowance at December 31, 2017, the effective rate for the year ended June 30, 2018, would have been 16% of income before income taxes.

Our effective tax rate for fiscal 2018 is less than the statutory rate primarily as a result of the reduction in federal tax rate from newly enacted tax legislation as well as the benefit derived from statutory depletion in excess of tax basis partly offset by the state of Louisiana income taxes. 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 relatively lower state income taxes because a significant legal settlement and derivative gains were not taxable in Louisiana.



	June 30, 2018			% of Income Before Income Taxes		June 30, 2017			% of Income Before Income Taxes		June 30, 2016			% of Income Before Income Taxes
Income tax provision computed at the statutory federal rate:	$	4,459,940		27.6	%	$	4,380,892		34.0	%	$	11,638,588		34.0	%
Reconciling items:
Adjustment of deferred income liability for lower statutory federal tax rate	(5,949,389		)	(36.8	)%	—			—	%	—			—	%
Change in valuation allowance due to newly enacted tax legislation	(111,818		)	(0.7	)%	—			—	%	—			—	%
Depletion in excess of tax basis	(2,433,530		)	(14.9	)%	(92,196		)	(0.7	)%	(2,242,620		)	(6.6	)%
State income taxes, net of federal tax benefit	718,337			4.4	%	522,713			4.1	%	196,415			0.6	%
Permanent differences related to stock-based compensation	(139,333		)	(0.9	)%	27,884			0.2	%	—			—	%
Other	23,824			0.1	%	1,371			—	%	(21,604		)	(0.1	)%
Income tax (benefit) provision	$	(3,431,969	)	(21.2	)%	$	4,840,664		37.6	%	$	9,570,779		28.0	%

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. Prior to 2017, 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. Also prior to 2017, 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. Beginning in 2017, all deferred tax assets and liabilities are classified as noncurrent. See note below on ASU 2015-17.



	Asset (Liability)
	June 30, 2018			June 30, 2017			June 30, 2016
Deferred tax assets:
Non-qualified stock-based compensation	$	144,956		$	367,159		$	553,182
Net operating loss carry-forwards	680,186			852,477			386,808
AMT credit carry-forward	—			110,564			—
Other	24,207			18,581			130,947
Gross deferred tax assets	849,349			1,348,781			1,070,937
Valuation allowance	(180,628		)	(292,446		)	(292,446		)
Total deferred tax assets	668,721			1,056,335			778,491
Deferred tax liability:
Oil and natural gas properties	(11,224,156		)	(16,882,626		)	(12,513,863		)
Total deferred tax liability	(11,224,156		)	(16,882,626		)	(12,513,863		)
Net deferred tax liability	$	(10,555,435	)	$	(15,826,291	)	$	(11,735,372	)

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



	June 30, 2018		June 30, 2017		June 30, 2016
Current deferred tax asset	$	—	$	—	$	105,321
Non-current deferred tax liability	10,555,435		15,826,291		11,840,693
Net liability	10,555,435		15,826,291		11,735,372

As the result of prospectively adopting ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes on July 1, 2016, current deferred tax assets have been subsequently netted together with noncurrent deferred income tax liabilities.

As of June 30, 2018, we had a federal tax loss carryforward of approximately $1.2 million that we acquired through the reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. We will be able to utilize a maximum of $0.3 million of these carryforwards in equal annual amounts of $39,648 through 2023 and the balance is not able to be utilized based on the provisions of IRC Section 382. We have recorded a valuation allowance for the portion of our net operating loss that is limited by IRC Section 382.

During fiscal 2016 we utilized the remaining amount of $25.3 million of net operating losses ("NOL's") created primarily from tax deductions in excess of book deductions related to the exercise of non-qualified stock options and incentive warrants in fiscal 2014. NOL's related to such stock-based awards had not affected our future tax provision for financial reporting purposes, nor had it been recognized as a deferred tax asset for these future benefits. In fiscal 2016, 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 of $9,650,657.

In addition, as of June 30, 2018, the Company has an estimated carryforward of percentage depletion in excess of basis of approximately $1.1 million. These future deductions are limited to 65% of taxable income in any period.

Net Income Per Share

12 Months Ended

Jun. 30, 2018

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,
	2018		2017		2016
Numerator
Net income attributable to common shareholders	$	19,618,484	$	6,790,883	$	23,986,060
Denominator
Weighted average number of common shares – Basic	33,126,469		33,034,480		32,810,375
Effect of dilutive securities:
Contingent restricted stock grants	52,066		53,546		9,378
Stock Options	—		22,534		41,478
Total weighted average dilutive securities	52,066		76,080		50,856
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,178,535		33,110,560		32,861,231
Net income per common share – Basic	$	0.59	$	0.21	$	0.73
Net income per common share – Diluted	$	0.59	$	0.21	$	0.73

The following were reflected in the calculation of diluted earnings per share in their respective fiscal years:



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

Credit Agreements	12 Months Ended
Credit Agreements	Jun. 30, 2018
Debt Disclosure [Abstract]
Credit Agreements	Credit Agreements Senior Secured Credit Agreement On April 11, 2016, the Company entered into a new three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. The Facility replaces the Company's previous unsecured credit facility which was set to expire on April 29, 2016 and was terminated in early April. The initial borrowing base under the Facility was set at $10 million and was subsequently increased to $40 million effective February 1, 2018. On May 25, 2018, we entered into the third amendment to our credit agreement governing the revolving credit facility to, among other things, extend the maturity date to April 11, 2021 and to increase the consolidated tangible net worth covenant discussed below. As of June 30, 2018, the Company was in compliance with all financial covenants contained in the Facility, and no amounts were outstanding under the Facility. 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 $50 million, all as defined under the Facility. In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $42,201 as of June 30, 2018.

Commitments and Contingencies

12 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

We are subject to various claims and contingencies in the normal course of business. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate. At a minimum, we disclose such matters if we believe it is reasonably possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will confirm a loss and we can reasonably estimate such loss and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.

On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. We vigorously defended the claims. Based on our assessment of the continuing costs of defending the Company in this litigation, we entered into a confidential settlement agreement and obtained a full release and dismissal of all claims asserted in this matter. Although the agreement is confidential, the amount of the settlement payment, which was recorded in general and administrative expense as of March 31, 2018 and paid by the Company in April, is not material to the financial position or operations of the Company.

Lease Commitments. We have a non-cancelable office space with a three year term ending on May 31, 2019. Future minimum lease commitments as of June 30, 2018 under this operating lease is as follows:



For the fiscal year ended June 30,
2019	$	66,984

Rent expense for the years ended June 30, 2018, 2017, and 2016 was $76,666, $80,472, and $182,626, respectively.

Concentrations of Credit Risk

12 Months Ended

Jun. 30, 2018

Risks and Uncertainties [Abstract]

Concentrations of Credit Risk

Major Customers. We market all of our oil and natural gas production from the properties we operate. We do not currently market our share of crude oil production from Delhi. Although we have the right to take our working interest production at Delhi in-kind, we are currently selling our oil under the Delhi operator's agreement with Plains Marketing L.P. for the delivery of our oil to a pipeline at the field. The majority of our operated gas, oil and condensate production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more of our net oil and natural gas revenues during the years ended June 30, 2018, 2017, and 2016. The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations.



	Year Ended June 30,
Customer	2018		2017		2016
Plains Marketing L.P. (Oil sales from Delhi)	92	%	97	%	99	%
American Midstream Gas Solutions (NGL sales from Delhi)	8	%	3	%	—	%
All others	—	%	—	%	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. 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").

Retirement Plan	12 Months Ended
Retirement Plan	Jun. 30, 2018
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 contributions fully vested when made. Our matching contributions to the Plan totaled $43,134, $53,113, and $88,348 for the years ended June 30, 2018, 2017, and 2016, respectively.

Derivatives	12 Months Ended
Derivatives	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	Derivatives In early June 2015, the Company began using derivative instruments to reduce its exposure to crude oil price volatility for a substantial portion of its near-term forecasted production. The Company's objectives for this program were to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The Company uses both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes. The Company accounts for derivatives under the provisions of ASC 815 Derivatives and 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, 2018 and 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 consisting of a realized gain of $3,315,123 on settled derivatives and an unrealized gain of $124,106 on unsettled derivatives.

Fair Value Measurement	12 Months Ended
Fair Value Measurement	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurement	Fair Value Measurement Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. Fair Value of Financial Instruments. The Company's other financial instruments consist of cash, cash equivalents, and restricted cash, receivables and payables. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature of these instruments. Other Fair Value Measurements. The initial measurement and any subsequent revision of asset retirement obligations at fair value are calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, surface restoration and reserve lives. Subsequent to initial recognition, revisions to estimated asset retirement obligations are made when changes occur for input 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]

Dehli Field Litigation Settlement	12 Months Ended
Dehli Field Litigation Settlement	Jun. 30, 2018
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.

Restructuring	12 Months Ended
Restructuring	Jun. 30, 2018
Restructuring and Related Activities [Abstract]
Restructuring	Restructuring During the quarter ended December 31, 2015, we consummated a plan to separate and transfer our GARP® artificial lift technology 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. At December 31, 2015, we recorded a $1,257,433 restructuring charge which included $59,339 of stock-based compensation, $628,866 of accrued separation and benefits expense and $569,228 for asset impairments discussed below. The non-impairment portion of the restructuring charge was based on agreements with the separated 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. 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 that fiscal year to reflect the difference between the original accrual and actual expenditures. In connection with the plan, we invested $108,750 in common and preferred stock of the new entity, Well Lift, Inc. ("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. As part of the above restructuring plan, we transferred our technology assets, including our patents and trademarks, to WLI in exchange for a perpetual royalty of 5% on all future gross revenues associated with the GARP^® technology. We reduced the carrying value of these exchanged technology assets to our estimate of their expected discounted net present value, which was $108,512. This estimate was based on the recent financial results from our artificial lift technology operations and the depressed state of the oil and gas industry and the potential upside outcomes were assigned relatively low probabilities for accounting purposes. The resulting impairment on the technology assets transferred together with impairments of less significant, non-technology assets that had no value to our remaining operations totaled $569,228.

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

12 Months Ended

Jun. 30, 2018

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

Costs incurred for oil and natural gas property acquisition, exploration and development activities

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $43,922, $471,864 and $140,151 during the years ended June 30, 2018, 2017, and 2016, respectively.



	For the Years Ended June 30,
	2018		2017		2016
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	—	$	—	$	—
Unproved property (a)	—		—		596,500
Exploration costs	—		—		—
Development costs	5,429,985		7,554,579		19,093,200
Total costs incurred for oil and natural gas activities	$	5,429,985	$	7,554,579	$	19,689,700

(a) In connection with the June 2016 Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500. This cost is included in properties subject to amortization.

Estimated Net Quantities of Proved Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2018, 2017, and 2016, which requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce.

Proved oil and natural gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows:



	Crude Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)		BOE
Proved developed and undeveloped reserves:
June 30, 2015	10,011,976		2,433,595		4,939		12,446,394
Revisions of previous estimates (a)	(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 (b)	508,123		(504,733	)	16		3,390
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(724,523	)	(43,910	)	(16	)	(768,433	)
June 30, 2017	8,372,150		1,686,228		—		10,058,378
Revisions of previous estimates (c)	369,971		(315,090	)	—		54,881
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(651,931	)	(93,366	)	—		(745,297	)
June 30, 2018	8,090,190		1,277,772		—		9,367,962
Proved developed reserves:
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
June 30, 2018	6,291,850		993,741		—		7,285,591
Proved undeveloped reserves:
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
June 30, 2018	1,798,340		284,031		—		2,082,371

(a) 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.

(b) 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.

(c) The positive crude oil revision resulted from better production performance during fiscal 2018. The negative NGL revision results primarily from lower expectations for ultimate NGL recoveries from the plant based on production data subsequent to the commencement of plant production.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas ("ASC 932"). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves and asset retirement obligations 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, 2018, 2017, and 2016 are as follows:



	For the Years Ended June 30,
	2018			2017			2016
Future cash inflows	$	521,533,765		$	425,094,736		$	383,491,193
Future production costs and severance taxes	(228,478,119		)	(213,115,443		)	(179,182,565		)
Future development costs	(22,213,269		)	(22,631,856		)	(16,595,047		)
Future income tax expenses	(50,810,883		)	(47,055,551		)	(45,713,438		)
Future net cash flows	220,031,494			142,291,886			142,000,143
10% annual discount for estimated timing of cash flows	(101,073,080		)	(59,354,333		)	(64,042,824		)
Standardized measure of discounted future net cash flows	$	118,958,414		$	82,937,553		$	77,957,319

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.



	For the Years Ended June 30,
	2018			2017			2016
	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	57.50	n/a	$	48.85	n/a	$	42.91	n/a

There were no natural gas reserves in 2018, 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 projected to be produced by the plant.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows:



	For the Years Ended June 30,
	2018			2017			2016
Balance, beginning of year	$	82,937,553		$	77,957,319		$	159,196,539
Net changes in sales prices and production costs related to future production	62,011,112			19,821,288			(120,832,747		)
Changes in estimated future development costs	267,547			(1,626,833		)	74,991
Sales of oil and gas produced during the period, net of production costs	(29,087,710		)	(23,649,087		)	(17,079,363		)
Net change due to extensions, discoveries, and improved recovery	—			—			—
Net change due to revisions in quantity estimates	888,896			(2,206,287		)	(18,821,014		)
Net change due to sales of minerals in place	—			—			—
Development costs incurred during the period	—			2,632,547			16,327,883
Accretion of discount	11,089,455			10,086,904			21,870,650
Net change in discounted income taxes	871,540			(5,045,279		)	36,598,239
Net changes in timing of production and other	(10,019,979		)	4,966,981			622,141
Balance, end of year	$	118,958,414		$	82,937,553		$	77,957,319

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Jun. 30, 2018

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

The following table presents summarized quarterly financial information for the fiscal years ended June 30, 2018 and 2017:



2018	First		Second		Third		Fourth
Revenues	$	8,537,871	$	11,066,911	$	10,249,566	$	11,426,864
Operating income	2,536,459		4,829,252		3,663,267		5,182,663
Net income available to common shareholders	$	2,140,532	$	9,876,848	$	3,068,354	$	4,532,750
Basic net income per share	$	0.06	$	0.30	$	0.09	$	0.14
Diluted net income per share	$	0.06	$	0.30	$	0.09	$	0.14



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 net income per share	$	0.02	$	0.07	$	0.07	$	0.05
Diluted net income per share	$	0.05	$	0.07	$	0.07	$	0.07

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Jun. 30, 2018
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 of prior periods 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.
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.
Restricted Cash	Restricted Cash. Funds legally designated for a specified purpose are classified as restricted cash. Such a balance is classified on the statement of financial position as either current or non-current depending on its expected use.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist 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 receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2018 and 2017, no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties	Oil and Natural Gas Properties. We use the full-cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.
Limitation on Capitalized Costs	Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent, and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; and 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, 2018, 2017 or 2016.
Other Property and Equipment	Other Property and Equipment. Other property and equipment includes building leasehold improvements, data processing and telecommunications equipment, office furniture and office equipment. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method. 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, restricted cash, 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 have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues.
Derivative Instruments	Derivative Instruments. The Company has used and may continue to use derivative transactions to reduce its exposure to oil, natural gas or NGL 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 ("DD&A"). 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 building improvements, office and computer 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 largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.
Earnings (Loss) Per Share	Earnings (Loss) Per Share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss 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	Recently Adopted Accounting Pronouncements. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. The Company retrospectively early adopted this guidance on April 1, 2018. ASU 2016-18 had no impact on the consolidated statements of cash flows for the previously reported interim periods of our current fiscal year and for prior fiscal year consolidated statements of cash flows presented in this annual report on Form 10-K. New Accounting Pronouncements Not Yet Adopted. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which will supersede most of the existing revenue recognition standards and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The update was issued to increase stakeholders’ awareness of the proposals for technical corrections and to expedite improvements. The Company will adopt these updates effective July 1, 2018, using the full retrospective approach, meaning any cumulative effect of initially applying the standard is recognized in the earliest period presented in the financial statements. The Company has finalized the detailed analysis of its contracts and of the impact of the standard on its contracts and found that there was no significant impact on its financial position or results of operations. Upon adoption of this standard, the Company will not be required to record a cumulative effect adjustment as the new standard does not have a quantitative impact on net income compared to existing generally accepted accounting principles. Also, upon adoption of the standard, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the new updates will have a material change on how it presents information regarding its revenue streams as compared to existing generally accepted accounting principles although certain revenue streams under the new standard will be presented on a net rather than gross basis. 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 investees) 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, 2018. 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. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“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. The Company will retrospectively adopt ASU 2016-15 on July 1, 2018, and does not expect its adoption to have a material effect on its consolidated statements of cash flows. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), which clarifies the definition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will adopt ASU 2017-01 effective July 1, 2018 on a prospective basis.

Prepaid Expenses and Other Current Assets (Tables)

12 Months Ended

Jun. 30, 2018

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

Schedule of prepaid expenses and other current assets

As of June 30, 2018 and June 30, 2017 our prepaid expenses and other current assets consisted of the following:



	June 30, 2018		June 30, 2017
Prepaid insurance	$	198,558	$	169,416
Prepaid federal and state income taxes	231,920		121,232
Retainers and deposits	11,089		7,553
Other prepaid expenses	82,940		89,471
Prepaid expenses and other current assets	$	524,507	$	387,672

Receivables (Tables)

12 Months Ended

Jun. 30, 2018

Receivables [Abstract]

Schedule of receivables

As of June 30, 2018 and June 30, 2017 our receivables consisted of the following:



	June 30, 2018		June 30, 2017
Receivables from oil and gas sales	$	3,940,998	$	2,722,880
Other	918		3,822
Total receivables	$	3,941,916	$	2,726,702

Property and Equipment (Tables)

12 Months Ended

Jun. 30, 2018

Property, Plant and Equipment [Abstract]

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

As of June 30, 2018 and June 30, 2017, our oil and natural gas properties and other property and equipment consisted of the following:



	June 30, 2018			June 30, 2017
Oil and natural gas properties:
Property costs subject to amortization	$	90,392,918		$	84,962,933
Less: Accumulated depreciation, depletion, and amortization	(29,153,172		)	(23,172,865		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	61,239,746			61,790,068
Other property and equipment:
Furniture, fixtures and office equipment, at cost	143,223			135,377
Less: Accumulated depreciation	(112,816		)	(94,688		)
Other property and equipment, net	$	30,407		$	40,689

Other Assets (Tables)

12 Months Ended

Jun. 30, 2018

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

Schedule of other assets

As of June 30, 2018 and June 30, 2017 our other assets consisted of the following:



	June 30, 2018			June 30, 2017
Royalty rights	108,512			108,512
Less: Accumulated amortization of royalty rights	(33,910		)	(20,346		)
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	(126,771		)	(70,504		)
Software license	20,662			—
Less: Accumulated amortization of software license	(1,380		)	—
Other assets, net	$	244,835		$	295,384

Accrued Liabilities and Other (Tables)

12 Months Ended

Jun. 30, 2018

Other Liabilities Disclosure [Abstract]

Other Current Liabilities

As of June 30, 2018 and June 30, 2017 our accrued liabilities and other consisted of the following:



	June 30, 2018		June 30, 2017
Accrued incentive and other compensation	$	415,182	$	413,113
Accrued severance (for two former employees)	160,089		—
Asset retirement obligations due within one year	35,539		35,115
Accrued royalties, including suspended accounts	11,498		17,708
Accrued franchise taxes	162,805		150,062
Accrued ad valorem taxes	89,773		108,641
Accrued liabilities and other	$	874,886	$	724,639

Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2018

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, 2018 and 2017:



	Years Ended
	2018			2017
Asset retirement obligations — beginning of period	$	1,288,743		$	962,196
Liabilities incurred	44,700			52,792
Liabilities settled	—			(157,164		)
Liabilities sold	—			(47,817		)
Accretion of discount	90,290			59,664
Revisions to previous estimates	(778		)	419,072
Asset retirement obligations — end of period	1,422,955			1,288,743
Less: current asset retirement obligations	(35,539		)	(35,115		)
Long-term portion of asset retirement obligations	$	1,387,416		$	1,253,628

Stockholders' Equity (Tables)

12 Months Ended

Jun. 30, 2018

Equity [Abstract]

Dividends declared and paid

The following table reflects the dividends paid per common share in each quarter within the respective three fiscal years:



	Fiscal Year
	2018		2017		2016
Fourth quarter ended June 30,	$	0.100	$	0.070	$	0.050
Third quarter ended March 31,	$	0.100	$	0.070	$	0.050
Second quarter ended December 31,	$	0.075	$	0.065	$	0.050
First quarter ended September 30,	$	0.075	$	0.050	$	0.050

Schedule of share repurchases

The following summarizes all treasury stock purchases by fiscal year:



	Fiscal Year
	2018		2017		2016
Number of treasury shares acquired	73,208		83,675		218,682
Average cost per share	$	7.80	$	6.42	$	5.78
Total cost of treasury shares acquired	$	571,083	$	537,014	$	1,263,402

Stock-Based Incentive Plan (Tables)

12 Months Ended

Jun. 30, 2018

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

Schedule of Valuation Assumptions

. The range of assumptions used in the Monte Carlo simulation valuations for the years ended June 30, 2017 and 2016 were as follows:



	Years Ended June 30
	2017			2016
Weighted average fair value of market-based awards granted	$	4.97		$	5.50
Risk-free interest rate	1.03		%	1.46		%
Expected life in years	2.83			3.83
Expected volatility	37.8		%	34.9		%
Dividend yield	3.5		%	3.3		%

Schedule of Restricted Stock transactions

Unvested Restricted Stock awards at June 30, 2018 consisted of the following:



Award Type	Number of Restricted Shares	Weighted Average Grant-Date Fair Value
Service-based awards	157,906	$	7.16
Performance-based awards	21,259	5.67
Market-based awards	20,312	5.44
Unvested at June 30, 2018	199,477	$	6.83

Unvested Contingent Restricted Stock awards at June 30, 2018 consisted of the following:



Award Type	Number of Contingent Restricted Shares	Weighted Average Grant-Date Fair Value
Performance-based awards	18,406	$	7.52
Market-based awards	10,156	3.42
Unvested at June 30, 2018	28,562	$	6.06

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2018:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2018		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	391,624		$	6.22	$	—
Service-based awards granted	136,907		7.53
Vested	(211,960	)	6.73
Forfeited	(117,094	)	5.78
Unvested at June 30, 2018	199,477		$	6.83	$	747,204	2.0

The following table summarizes Contingent Restricted Stock activity for fiscal 2018:



	Number of Restricted Stock Units		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2018 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2017	113,270		$	4.64
Forfeited	(38,078	)	5.17
Vested	(46,630	)	3.34
Unvested at June 30, 2018	28,562		$	6.06	$	12,251	1.0

(1) Excludes $78,159 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Schedule of Restricted Stock Activity

The following is a summary of Restricted Stock vestings for the last three fiscal years:



	Year Ended June 30,
	2018		2017		2016
Vesting-date intrinsic value of Restricted Stock	$	1,622,937	$	1,478,478	$	485,580
Grant-date fair value of vested Restricted Stock	$	1,427,498	$	1,520,569	$	757,229

The following is a summary of Contingent Restricted Stock vestings for the last three fiscal years:



	Year Ended June 30,
	2018		2017		2016
Vest-date intrinsic value of Contingent Restricted Stock	$	347,852	$	183,572	$	—
Grant-date fair value of vested Contingent Restricted Stock	$	155,744	$	197,170	$	—

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Jun. 30, 2018

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, 2018, 2017, and 2016 are as follows:



	June 30,
	2018		2017			2016
Income taxes paid	$	1,826,754	$	1,495,377		$	540,000
Income tax refunds	—		—			1,556,999
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	1,695,218		(3,076,245		)	(2,250,048		)
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	43,922		471,864			140,151
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		)

Income Taxes (Tables)

12 Months Ended

Jun. 30, 2018

Income Tax Disclosure [Abstract]

Schedule of components of income tax provision (benefit)

The components of our income tax provision (benefit) are as follows:



	June 30, 2018			June 30, 2017		June 30, 2016
Current:
Federal	$	1,186,649		$	168,152	$	8,731,290
State	652,238			581,593		264,254
Total current income tax provision	1,838,887			749,745		8,995,544
Deferred:
Federal	(5,498,890		)	3,880,522		541,891
State	228,034			210,397		33,344
Total deferred income tax provision	(5,270,856		)	4,090,919		575,235
	$	(3,431,969	)	$	4,840,664	$	9,570,779

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



	June 30, 2018			% of Income Before Income Taxes		June 30, 2017			% of Income Before Income Taxes		June 30, 2016			% of Income Before Income Taxes
Income tax provision computed at the statutory federal rate:	$	4,459,940		27.6	%	$	4,380,892		34.0	%	$	11,638,588		34.0	%
Reconciling items:
Adjustment of deferred income liability for lower statutory federal tax rate	(5,949,389		)	(36.8	)%	—			—	%	—			—	%
Change in valuation allowance due to newly enacted tax legislation	(111,818		)	(0.7	)%	—			—	%	—			—	%
Depletion in excess of tax basis	(2,433,530		)	(14.9	)%	(92,196		)	(0.7	)%	(2,242,620		)	(6.6	)%
State income taxes, net of federal tax benefit	718,337			4.4	%	522,713			4.1	%	196,415			0.6	%
Permanent differences related to stock-based compensation	(139,333		)	(0.9	)%	27,884			0.2	%	—			—	%
Other	23,824			0.1	%	1,371			—	%	(21,604		)	(0.1	)%
Income tax (benefit) provision	$	(3,431,969	)	(21.2	)%	$	4,840,664		37.6	%	$	9,570,779		28.0	%

Schedule of components of deferred taxes

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



	June 30, 2018		June 30, 2017		June 30, 2016
Current deferred tax asset	$	—	$	—	$	105,321
Non-current deferred tax liability	10,555,435		15,826,291		11,840,693
Net liability	10,555,435		15,826,291		11,735,372



	Asset (Liability)
	June 30, 2018			June 30, 2017			June 30, 2016
Deferred tax assets:
Non-qualified stock-based compensation	$	144,956		$	367,159		$	553,182
Net operating loss carry-forwards	680,186			852,477			386,808
AMT credit carry-forward	—			110,564			—
Other	24,207			18,581			130,947
Gross deferred tax assets	849,349			1,348,781			1,070,937
Valuation allowance	(180,628		)	(292,446		)	(292,446		)
Total deferred tax assets	668,721			1,056,335			778,491
Deferred tax liability:
Oil and natural gas properties	(11,224,156		)	(16,882,626		)	(12,513,863		)
Total deferred tax liability	(11,224,156		)	(16,882,626		)	(12,513,863		)
Net deferred tax liability	$	(10,555,435	)	$	(15,826,291	)	$	(11,735,372	)

Net Income Per Share (Tables)

12 Months Ended

Jun. 30, 2018

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,
	2018		2017		2016
Numerator
Net income attributable to common shareholders	$	19,618,484	$	6,790,883	$	23,986,060
Denominator
Weighted average number of common shares – Basic	33,126,469		33,034,480		32,810,375
Effect of dilutive securities:
Contingent restricted stock grants	52,066		53,546		9,378
Stock Options	—		22,534		41,478
Total weighted average dilutive securities	52,066		76,080		50,856
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	33,178,535		33,110,560		32,861,231
Net income per common share – Basic	$	0.59	$	0.21	$	0.73
Net income per common share – Diluted	$	0.59	$	0.21	$	0.73

Schedule of outstanding potentially dilutive securities

The following were reflected in the calculation of diluted earnings per share in their respective fiscal years:



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

Commitments and Contingencies (Tables)

12 Months Ended

Jun. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum lease commitments under the operating lease

Future minimum lease commitments as of June 30, 2018 under this operating lease is as follows:



For the fiscal year ended June 30,
2019	$	66,984

Concentrations of Credit Risk (Tables)

12 Months Ended

Jun. 30, 2018

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, 2018, 2017, and 2016. The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations.



	Year Ended June 30,
Customer	2018		2017		2016
Plains Marketing L.P. (Oil sales from Delhi)	92	%	97	%	99	%
American Midstream Gas Solutions (NGL sales from Delhi)	8	%	3	%	—	%
All others	—	%	—	%	1	%
Total	100	%	100	%	100	%

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

12 Months Ended

Jun. 30, 2018

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,
	2018		2017		2016
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	—	$	—	$	—
Unproved property (a)	—		—		596,500
Exploration costs	—		—		—
Development costs	5,429,985		7,554,579		19,093,200
Total costs incurred for oil and natural gas activities	$	5,429,985	$	7,554,579	$	19,689,700

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, 2015	10,011,976		2,433,595		4,939		12,446,394
Revisions of previous estimates (a)	(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 (b)	508,123		(504,733	)	16		3,390
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(724,523	)	(43,910	)	(16	)	(768,433	)
June 30, 2017	8,372,150		1,686,228		—		10,058,378
Revisions of previous estimates (c)	369,971		(315,090	)	—		54,881
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(651,931	)	(93,366	)	—		(745,297	)
June 30, 2018	8,090,190		1,277,772		—		9,367,962
Proved developed reserves:
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
June 30, 2018	6,291,850		993,741		—		7,285,591
Proved undeveloped reserves:
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
June 30, 2018	1,798,340		284,031		—		2,082,371

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, 2018, 2017, and 2016 are as follows:



	For the Years Ended June 30,
	2018			2017			2016
Future cash inflows	$	521,533,765		$	425,094,736		$	383,491,193
Future production costs and severance taxes	(228,478,119		)	(213,115,443		)	(179,182,565		)
Future development costs	(22,213,269		)	(22,631,856		)	(16,595,047		)
Future income tax expenses	(50,810,883		)	(47,055,551		)	(45,713,438		)
Future net cash flows	220,031,494			142,291,886			142,000,143
10% annual discount for estimated timing of cash flows	(101,073,080		)	(59,354,333		)	(64,042,824		)
Standardized measure of discounted future net cash flows	$	118,958,414		$	82,937,553		$	77,957,319

Schedule of NYMEX prices used in determining future cash flows



	For the Years Ended June 30,
	2018			2017			2016
	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	57.50	n/a	$	48.85	n/a	$	42.91	n/a

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,
	2018			2017			2016
Balance, beginning of year	$	82,937,553		$	77,957,319		$	159,196,539
Net changes in sales prices and production costs related to future production	62,011,112			19,821,288			(120,832,747		)
Changes in estimated future development costs	267,547			(1,626,833		)	74,991
Sales of oil and gas produced during the period, net of production costs	(29,087,710		)	(23,649,087		)	(17,079,363		)
Net change due to extensions, discoveries, and improved recovery	—			—			—
Net change due to revisions in quantity estimates	888,896			(2,206,287		)	(18,821,014		)
Net change due to sales of minerals in place	—			—			—
Development costs incurred during the period	—			2,632,547			16,327,883
Accretion of discount	11,089,455			10,086,904			21,870,650
Net change in discounted income taxes	871,540			(5,045,279		)	36,598,239
Net changes in timing of production and other	(10,019,979		)	4,966,981			622,141
Balance, end of year	$	118,958,414		$	82,937,553		$	77,957,319

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, 2018

Summary of quarterly financial information

The following table presents summarized quarterly financial information for the fiscal years ended June 30, 2018 and 2017:



2018	First		Second		Third		Fourth
Revenues	$	8,537,871	$	11,066,911	$	10,249,566	$	11,426,864
Operating income	2,536,459		4,829,252		3,663,267		5,182,663
Net income available to common shareholders	$	2,140,532	$	9,876,848	$	3,068,354	$	4,532,750
Basic net income per share	$	0.06	$	0.30	$	0.09	$	0.14
Diluted net income per share	$	0.06	$	0.30	$	0.09	$	0.14



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 net income per share	$	0.02	$	0.07	$	0.07	$	0.05
Diluted net income per share	$	0.05	$	0.07	$	0.07	$	0.07

Summary of Significant Accounting Policies (Details)	12 Months Ended
Summary of Significant Accounting Policies (Details)	Jun. 30, 2018 USD ($)	Jun. 30, 2017 USD ($)
Accounting Policies [Abstract]
Allowance for doubtful accounts	$ 0	$ 0
Oil and natural gas properties
Limitation on Capitalized Costs
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
Discount rate \| Oil and natural gas properties
Limitation on Capitalized Costs
Discount rate for present value (as a percent)	0.10

Enduro Purchase and Sale Agreement and Related Subsequent Events - Additional Information (Details) - USD ($) $ in Thousands		12 Months Ended
	May 15, 2018	Jun. 30, 2018
Asset Acquisition [Line Items]
Third party due diligence expense		$ 400
Affiliate of Enduro Resource Partners LLC
Asset Acquisition [Line Items]
Purchase price of oil and gas assets	$ 27,500
Escrow deposit	2,750
Proceeds from break-up fee	$ 1,100

Prepaid Expenses and Other Current Assets (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 198,558	$ 169,416
Prepaid federal and state income taxes	231,920	121,232
Retainers and deposits	11,089	7,553
Other prepaid expenses	82,940	89,471
Prepaid expenses and other current assets	$ 524,507	$ 387,672

Receivables (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017
Receivables [Abstract]
Receivables from oil and gas sales	$ 3,940,998	$ 2,722,880
Other	918	3,822
Total receivables	$ 3,941,916	$ 2,726,702

Property and Equipment - Summary of Property and Equipment (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017
Oil and natural gas properties:
Property costs subject to amortization	$ 90,392,918	$ 84,962,933
Less: Accumulated depreciation, depletion, and amortization	(29,153,172)	(23,172,865)
Unproved properties not subject to amortization	0	0
Oil and natural gas properties, net	61,239,746	61,790,068
Other property and equipment:
Furniture, fixtures and office equipment, at cost	143,223	135,377
Less: Accumulated depreciation	(112,816)	(94,688)
Other property and equipment, net	$ 30,407	$ 40,689

Property and Equipment - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Delhi Field
Property, Plant and Equipment [Line Items]
Capital expenditures	$ 5.4	$ 7.1

Other Assets (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Royalty rights	$ 108,512	$ 108,512
Less: Accumulated amortization of royalty rights	(33,910)	(20,346)
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	(126,771)	(70,504)
Software license	20,662	0
Less: Accumulated amortization of software license	(1,380)	0
Other assets, net	$ 244,835	$ 295,384

Other Assets - Additional Information (Details) - Well Lift Inc.	12 Months Ended
	Jun. 30, 2018
Line of Credit Facility [Line Items]
Perpetual royalty percentage	5.00%
Ownership percentage	17.50%

Accrued Liabilities and Other - Schedule of Other Current Liabilities (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017
Other Liabilities Disclosure [Abstract]
Accrued incentive and other compensation	$ 415,182	$ 413,113
Accrued severance (for two former employees)	160,089	0
Asset retirement obligations due within one year	35,539	35,115
Accrued royalties, including suspended accounts	11,498	17,708
Accrued franchise taxes	162,805	150,062
Accrued ad valorem taxes	89,773	108,641
Accrued liabilities and other	$ 874,886	$ 724,639

Asset Retirement Obligations - Summary of Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Reconciliation of the beginning and ending asset retirement obligation
Asset retirement obligations—beginning of period	$ 1,288,743	$ 962,196
Liabilities incurred	44,700	52,792
Liabilities settled	0	(157,164)
Liabilities sold	0	(47,817)
Accretion of discount	90,290	59,664	$ 49,054
Revisions to previous estimates	(778)	419,072
Asset retirement obligations—ending of period	1,422,955	1,288,743	$ 962,196
Less: current asset retirement obligations	(35,539)	(35,115)
Long-term portion of asset retirement obligations	$ 1,387,416	$ 1,253,628

Stockholders' Equity - Narrative (Details) - USD ($)	1 Months Ended			12 Months Ended
Stockholders' Equity - Narrative (Details) - USD ($)	Nov. 30, 2016	Sep. 30, 2016	Jun. 30, 2015	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016	May 12, 2015
Class of Stock [Line Items]
Common stock, outstanding shares				33,080,543	33,087,308
Dividends paid				$ 11,594,541	$ 8,432,435	$ 6,565,823
Total cost of treasury shares acquired				571,083	537,014	1,263,402
Aggregate redemption cost					7,932,975
Cash dividends to preferred stockholders				$ 0	$ 250,990	$ 674,302
Series A Cumulative Preferred Stock
Class of Stock [Line Items]
Issuance of preferred stock (in shares)		317,319
Preferred stock dividend rate (as a percent)				8.50%
Preferred stock, liquidation preference (in dollars per share)	$ 25.00
Common Stock
Class of Stock [Line Items]
Purchases of treasury stock (shares)				73,208	83,675	218,682
Preferred
Class of Stock [Line Items]
Aggregate redemption cost					$ 317
Preferred \| Series A Cumulative Preferred Stock
Class of Stock [Line Items]
Aggregate redemption cost	$ 7,932,975
Deemed dividend		$ 1,002,440
Cash dividends to preferred stockholders					$ 250,990	$ 674,302
2015 Share Repurchase Program \| Common Stock
Class of Stock [Line Items]
Amount authorized to be repurchased							$ 5,000,000
Purchases of treasury stock (shares)			265,762	73,208	83,675	218,682
Treasury stock acquired, average cost (in USD per share)			$ 6.05	$ 7.80	$ 6.42	$ 5.78
Total cost of treasury shares acquired			$ 1,609,008	$ 571,083	$ 537,014	$ 1,263,402

Stockholders' Equity - Dividends (Details) - $ / shares	12 Months Ended
Stockholders' Equity - Dividends (Details) - $ / shares	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Dividends Paid 1
Dividends Payable [Line Items]
Cash dividends paid (per common share)	$ 0.10	$ 0.07	$ 0.05
Dividends Paid 2
Dividends Payable [Line Items]
Cash dividends paid (per common share)	0.10	0.07	0.05
Dividends Paid 3
Dividends Payable [Line Items]
Cash dividends paid (per common share)	0.075	0.065	0.05
Dividends Paid 4
Dividends Payable [Line Items]
Cash dividends paid (per common share)	$ 0.075	$ 0.05	$ 0.05

Stockholders' Equity - Treasury Shares (Details) - USD ($)	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Equity, Class of Treasury Stock [Line Items]
Total cost of treasury shares acquired		$ 571,083	$ 537,014	$ 1,263,402
Common Stock
Equity, Class of Treasury Stock [Line Items]
Number of treasury shares acquired (shares)		73,208	83,675	218,682
Common Stock \| 2015 Share Repurchase Program
Equity, Class of Treasury Stock [Line Items]
Number of treasury shares acquired (shares)	265,762	73,208	83,675	218,682
Average cost per share (in USD per share)	$ 6.05	$ 7.80	$ 6.42	$ 5.78
Total cost of treasury shares acquired	$ 1,609,008	$ 571,083	$ 537,014	$ 1,263,402

Stock-Based Incentive Plan - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016	Dec. 08, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise of stock options (shares)		35,231
Stock options intrinsic value		$ 188,821
Shares unexercised (shares)		0
Restructuring charges	$ 0	$ 4,488	$ 1,257,433
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Option vested (in shares)	0	0	0
Restricted Stock, Service Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	1 year
Fair value at grant date, per share (in dollars per share)	$ 7.53
Shares granted (in shares)	136,907
Restricted Stock, Service Based \| Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)	69,963
Restricted Stock, Service Based \| Director
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted (in shares)	66,944
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares forfeited (shares)	117,094
Restricted stock, vested (shares)	211,960
Non-cash stock-based compensation expense	$ 1,366,764	$ 1,180,618	$ 1,809,548
Restructuring charges			$ 59,339
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)	963,093
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
2004 Stock Plan \| Other Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period (in years)	4 years
2004 Stock Plan \| Service-Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period (in years)	1 year
2004 Stock Plan \| Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	4 years
2004 Stock Plan \| Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years

Stock-Based Incentive Plan - Fair Value Assumptions (Details) - $ / shares	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	1.03%	1.46%
Expected life in years	2 years 9 months 29 days	3 years 9 months 29 days
Expected volatility	37.80%	34.90%
Dividend yield	3.50%	3.30%
Restricted Stock, Market Based
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average fair value of market-based awards granted (in dollars per share)	$ 4.97	$ 5.50

Stock-Based Incentive Plan - Schedule of Restricted Stock (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Restricted Stock
Number of Restricted Shares
Nonvested, beginning of period (shares)	391,624
Vested (shares)	(211,960)
Forfeited (shares)	(117,094)
Nonvested, end of period (shares)	199,477
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, beginning of period (in USD per share)	$ 6.22
Vested, weighted average grant date fair value (in USD per share)	6.73
Forfeited, weighted average grant date fair value (in USD per share)	5.78
Weighted average grant date fair value, end of period (in USD per share)	$ 6.83
Unamortized compensation expense	$ 747,204	$ 0
Weighted Average Remaining Amortization Period (in years)	2 years
Restricted Stock, Service Based
Number of Restricted Shares
Grants (shares)	136,907
Nonvested, end of period (shares)	157,906
Weighted Average Grant-Date Fair Value
Grants, weighted average grant date fair value (in USD per share)	$ 7.53
Weighted average grant date fair value, end of period (in USD per share)	$ 7.16
Restricted Stock, Performance Based
Number of Restricted Shares
Nonvested, end of period (shares)	21,259
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, end of period (in USD per share)	$ 5.67
Restricted Stock, Market Based
Number of Restricted Shares
Nonvested, end of period (shares)	20,312
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, end of period (in USD per share)	$ 5.44

Stock-Based Incentive Plan - Vesting Date Restricted Stock (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting-date intrinsic value of Restricted Stock	$ 1,622,937	$ 1,478,478	$ 485,580
Grant-date fair value of vested Restricted Stock	1,427,498	1,520,569	757,229
Contingent Restricted Stock Grants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting-date intrinsic value of Restricted Stock	347,852	183,572	0
Grant-date fair value of vested Restricted Stock	$ 155,744	$ 197,170	$ 0

Stock-Based Incentive Plan - Schedule of Contingent Restricted Stock (Details)	12 Months Ended
	Jun. 30, 2018 USD ($) $ / shares shares
Contingent Restricted Stock, Performance Based [Member]
Number of Restricted Stock Units
Nonvested, end of period (shares) \| shares	18,406
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, end of period (in USD per share) \| $ / shares	$ 7.52
Potential future compensation expense \| $	$ 78,159
Contingent Restricted Stock, Market Based [Member]
Number of Restricted Stock Units
Nonvested, end of period (shares) \| shares	10,156
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, end of period (in USD per share) \| $ / shares	$ 3.42
Contingent Restricted Stock Grants
Number of Restricted Stock Units
Nonvested, beginning of period (shares) \| shares	113,270
Forfeited (shares) \| shares	(38,078)
Vested (shares) \| shares	(46,630)
Nonvested, end of period (shares) \| shares	28,562
Weighted Average Grant-Date Fair Value
Weighted average grant date fair value, beginning of period (in USD per share) \| $ / shares	$ 4.64
Forfeited, weighted average grant date fair value (in USD per share) \| $ / shares	5.17
Vested, weighted average grant date fair value (in USD per share) \| $ / shares	3.34
Weighted average grant date fair value, end of period (in USD per share) \| $ / shares	$ 6.06
Unamortized compensation expense \| $	$ 12,251
Weighted Average Remaining Amortization Period (in years)	1 year

Supplemental Disclosure of Cash Flow Information - Schedule of Supplement Cash Flow (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Supplemental Cash Flow Elements [Abstract]
Income taxes paid	$ 1,826,754	$ 1,495,377	$ 540,000
Income tax refunds	0	0	1,556,999
Non-cash transactions:
Increase (decrease) in accrued purchases of property and equipment	1,695,218	(3,076,245)	(2,250,048)
Deferred loan costs charged to oil and gas property costs	0	0	107,196
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	43,922	471,864	140,151
Mengel working interest acquired in Delhi Field litigation settlement	0	0	596,500
Royalty rights acquired through non-monetary exchange of patent and trademark assets	0	0	108,512
Previously acquired Company shares swapped by holders to pay stock option exercise price	0	77,156	76,500
Accrued purchases of treasury stock	$ 0	$ 0	$ (170,283)

Income Taxes - Narrative (Details) - USD ($)	6 Months Ended	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Dec. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Operating Loss Carryforwards [Line Items]
Tax rate one time excluding adjustment		16.00%
Statutory tax rate		27.60%	34.00%	34.00%
Blended income tax rate		27.55%
Deferred tax benefit	$ 6,100,000	$ 5,949,389	$ 0	$ 0
Income tax rate percentage		(21.20%)	37.60%	28.00%
Unrecognized tax benefits		$ 0	$ 0	$ 0
Tax loss carryforwards from exercise of options and warrants				25,300,000
Tax benefits related to stock-based compensation		0	$ 0	$ 9,650,657
Mineral Property Depletion
Operating Loss Carryforwards [Line Items]
Tax carryforward		1,100,000
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

Income Taxes - Components of Income Tax Provision (Benefit) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Current:
Federal	$ 1,186,649	$ 168,152	$ 8,731,290
State	652,238	581,593	264,254
Total current income tax provision	1,838,887	749,745	8,995,544
Deferred:
Federal	(5,498,890)	3,880,522	541,891
State	228,034	210,397	33,344
Total deferred income tax provision	(5,270,856)	4,090,919	575,235
Total income tax provision	$ (3,431,969)	$ 4,840,664	$ 9,570,779

Income Taxes - Reconciliation of Statutory and Income Tax Expense (Details) - USD ($)	6 Months Ended	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Income tax provision (benefit) computed at the statutory federal rate		$ 4,459,940	$ 4,380,892	$ 11,638,588
Adjustment of deferred income liability for lower statutory federal tax rate	$ (6,100,000)	(5,949,389)	0	0
Change in valuation allowance due to newly enacted tax legislation		(111,818)	0	0
Depletion in excess of tax basis		(2,433,530)	(92,196)	(2,242,620)
State income taxes, net of federal tax benefit		718,337	522,713	196,415
Permanent differences related to stock-based compensation		(139,333)	27,884	0
Other		23,824	1,371	(21,604)
Total income tax provision		$ (3,431,969)	$ 4,840,664	$ 9,570,779
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Income tax (benefit) provision computed at the statutory federal rate		27.60%	34.00%	34.00%
Adjustment of deferred income liability for lower statutory federal tax rate		(36.80%)	0.00%	0.00%
Change in valuation allowance due to newly enacted tax legislation		(0.70%)	0.00%	0.00%
Depletion in excess of tax basis		(14.90%)	(0.70%)	(6.60%)
State income taxes, net of federal tax benefit		4.40%	4.10%	0.60%
Permanent differences related to stock-based compensation		(0.90%)	0.20%	0.00%
Other		0.10%	0.00%	(0.10%)
Income tax (benefit) provision		(21.20%)	37.60%	28.00%

Income Taxes - Schedule of Deferred Income Taxes (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Deferred tax assets:
Non-qualified stock-based compensation	$ 144,956	$ 367,159	$ 553,182
Net operating loss carry-forwards	680,186	852,477	386,808
AMT credit carry-forward	0	110,564	0
Other	24,207	18,581	130,947
Gross deferred tax assets	849,349	1,348,781	1,070,937
Valuation allowance	(180,628)	(292,446)	(292,446)
Total deferred tax assets	668,721	1,056,335	778,491
Deferred tax liability:
Oil and natural gas properties	(11,224,156)	(16,882,626)	(12,513,863)
Total deferred tax liability	(11,224,156)	(16,882,626)	(12,513,863)
Net deferred tax liability	$ (10,555,435)	$ (15,826,291)	$ (11,735,372)

Income Taxes - Balance Sheet Items (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Current deferred tax asset	$ 0	$ 0	$ 105,321
Non-current deferred tax liability	10,555,435	15,826,291	11,840,693
Net liability	$ 10,555,435	$ 15,826,291	$ 11,735,372

Net Income Per Share - Schedule of Basic and Diluted Earnings (Loss) Per Share (Details) - USD ($)	3 Months Ended								12 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Numerator
Net income attributable to common shareholders	$ 4,532,750	$ 3,068,354	$ 9,876,848	$ 2,140,532	$ 1,500,761	$ 2,419,143	$ 2,307,634	$ 563,345	$ 19,618,484	$ 6,790,883	$ 23,986,060
Denominator
Weighted average number of common shares—Basic (in shares)									33,126,469	33,034,480	32,810,375
Effect of dilutive securities:
Total weighted average dilutive securities (in shares)									52,066	76,080	50,856
Weighted average number of common shares and dilutive potential common shares used in diluted EPS (in shares)									33,178,535	33,110,560	32,861,231
Net income per common share - Basic (in dollars per share)	$ 0.14	$ 0.09	$ 0.30	$ 0.06	$ 0.05	$ 0.07	$ 0.07	$ 0.02	$ 0.59	$ 0.21	$ 0.73
Net income per common share - Diluted (in dollars per share)	$ 0.14	$ 0.09	$ 0.30	$ 0.06	$ 0.07	$ 0.07	$ 0.07	$ 0.05	$ 0.59	$ 0.21	$ 0.73
Contingent restricted stock grants
Effect of dilutive securities:
Weighted average dilutive securities (in shares)									52,066	53,546	9,378
Stock Options
Effect of dilutive securities:
Weighted average dilutive securities (in shares)									0	22,534	41,478

Net Income Per Share - Schedule of Outstanding Potentially Dilutive Securities (Details) - $ / shares	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Exercise Price (in dollars per share)			$ 0.61
Outstanding (in shares)			126,403
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)	28,562	113,270	91,172
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Weighted Average Exercise Price (in dollars per share)			$ 2.19
Outstanding (in shares)			35,231

Credit Agreements (Details) - Line of Credit - Senior Secured Reserve-Based Credit Facility - Revolving Credit Facility	Apr. 11, 2016 USD ($)	Jun. 30, 2018 USD ($)	Feb. 01, 2018 USD ($)
Debt Instrument [Line Items]
Term of debt instrument	3 years
Maximum borrowing capacity	$ 50,000,000
Initial borrowing base	$ 10,000,000		$ 40,000,000
Placement fee percentage	0.50%
Placement fee amount	$ 50,000
Commitment fee percentage	0.25%
Maximum total leverage ratio	3
Debt service coverage ratio	1.10
Minimum consolidated tangible net worth	$ 50,000,000
Debt issuance costs	$ 168,972
Unamortized debt issuance costs		$ 42,201
LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	2.75%
Prime Rate
Debt Instrument [Line Items]
Basis spread on variable rate	1.00%

Commitments and Contingencies - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Term of operating lease (in years)	3 years
Rent expense	$ 76,666	$ 80,472	$ 182,626

Commitments and Contingencies - Schedule of Future Minimum Lease Commitments (Details)	Jun. 30, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2019	$ 66,984

Concentrations of Credit Risk - Schedule of Credit Risk (Details) - Net revenue - Major Customers	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
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	92.00%	97.00%	99.00%
American Midstream Gas Solutions (NGL sales from Delhi)
Concentrations of Credit Risk
Percent of Total Revenue	8.00%	3.00%	0.00%
All others
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	0.00%	1.00%

Retirement Plan (Details) - USD ($)	12 Months Ended
Retirement Plan (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
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	$ 43,134	$ 53,113	$ 88,348

Derivatives (Details) - USD ($)	12 Months Ended
Derivatives (Details) - USD ($)	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net asset position of derivatives with counterparty	$ 0	$ 14,132	$ 0
Gain on derivatives	29,758	3,439,229
Gain on settled derivatives	43,890	3,315,123
Unrealized gain (loss) on derivatives	$ (14,132)	$ 124,106

Dehli Field Litigation Settlement (Details) - USD ($)		12 Months Ended
Dehli Field Litigation Settlement (Details) - USD ($)	Jun. 24, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Loss Contingencies [Line Items]
Delhi field litigation settlement gain		$ 0	$ 0	$ 28,096,500
Fair value of litigation settlement		$ 0	$ 0	$ 596,500
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

Restructuring - Investments in Well Lift Inc (Details) - USD ($)	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2015	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Restructuring Cost and Reserve [Line Items]
Restructuring charges				$ 0	$ 4,488	$ 1,257,433
Stock-based compensation				1,366,764	1,180,618	$ 1,809,548
Investment in Well Lift Inc., at cost				$ 108,750	108,750
GARP
Restructuring Cost and Reserve [Line Items]
Restructuring charges		$ 1,257,433
Restructuring reserve	$ 628,866	628,866	$ 628,866
Adjustment to Cost					$ 4,488
GARP \| Restructuring charges
Restructuring Cost and Reserve [Line Items]
Stock-based compensation			59,339
Well Lift Inc.
Restructuring Cost and Reserve [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
Exchange of Assets \| Well Lift Inc. \| GARP
Restructuring Cost and Reserve [Line Items]
Total impairments	$ 569,228

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Narrative (Details) - USD ($)		12 Months Ended
	Jun. 24, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Reserve Quantities [Line Items]
Oil and natural gas property costs attributable to the recognition of asset retirement obligations		$ 43,922	$ 471,864	$ 140,151
Fair value of litigation settlement		$ 0	$ 0	$ 596,500
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
Dehli Field Litigation \| Denbury Resources, Inc
Reserve Quantities [Line Items]
Working interest in Mengal Sand Interval	23.90%
Fair value of litigation settlement	$ 596,500

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of Costs Incurred and Capitalized in Oil and Natural Gas Property Acquisition, Exploration, and Development (Details) - USD ($)

12 Months Ended

Jun. 30, 2018

Jun. 30, 2017

Jun. 30, 2016

Property acquisition costs:

Proved property

$ 0

Unproved property

^[1]

596,500

Exploration costs

Development costs

5,429,985

7,554,579

19,093,200

Total costs incurred for oil and natural gas activities

$ 5,429,985

$ 7,554,579

$ 19,689,700

[1]	In connection with the June 2016 Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500. This cost is included in properties subject to amortization.

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Estimated Quantities of Proved Oil and Natural Gas Reserves (Details)

12 Months Ended

Jun. 30, 2018

Boe

Mcf

bbl

Jun. 30, 2017

Boe

Mcf

bbl

Jun. 30, 2016

Boe

Mcf

bbl

Jun. 30, 2015

Boe

Mcf

bbl

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Balance at the beginning of the period (in BOE) | Boe

10,058,378

10,823,421

12,446,394

Revisions of previous estimates (in BOE) | Boe

54,881

^[1]

3,390

^[2]

(964,171)

^[3]

Improved recovery, extensions and discoveries (in BOE) | Boe

Sales of minerals in place (in BOE) | Boe

Production (sales volumes) (in BOE) | Boe

(745,297)

(768,433)

(658,802)

Balance at the end of the period (in BOE) | Boe

9,367,962

10,058,378

10,823,421

Proved developed reserves (in BOE) | Boe

7,285,591

7,950,192

7,168,249

7,349,626

Proved undeveloped reserves (in BOE) | Boe

2,082,371

2,108,186

3,655,172

5,096,768

Crude Oil

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Balance at the beginning of the period (in Bbls/Mcf)

8,372,150

8,588,550

10,011,976

Revisions of previous estimates (in Bbls/Mcf)

369,971

^[1]

508,123

^[2]

(765,385)

^[3]

Improved recovery, extensions and discoveries (in Bbls/Mcf)

Sales of minerals in place (in Bbls/Mcf)

Production (sales volumes) (in Bbls/Mcf)

(651,931)

(724,523)

(658,041)

Balance at the end of the period (in Bbls/Mcf)

8,090,190

8,372,150

8,588,550

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Proved developed reserves (in Bbls/Mcf)

6,291,850

6,617,389

7,168,249

7,347,231

Proved undeveloped reserves (in Bbls/Mcf)

1,798,340

1,754,761

1,420,301

2,664,745

Natural Gas Liquids

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Balance at the beginning of the period (in Bbls/Mcf)

1,686,228

2,234,871

2,433,595

Revisions of previous estimates (in Bbls/Mcf)

(315,090)

^[1]

(504,733)

^[2]

(198,233)

^[3]

Improved recovery, extensions and discoveries (in Bbls/Mcf)

Sales of minerals in place (in Bbls/Mcf)

Production (sales volumes) (in Bbls/Mcf)

(93,366)

(43,910)

(491)

Balance at the end of the period (in Bbls/Mcf)

1,277,772

1,686,228

2,234,871

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Proved developed reserves (in Bbls/Mcf)

993,741

1,332,803

1,572

Proved undeveloped reserves (in Bbls/Mcf)

284,031

353,425

2,234,871

2,432,023

Natural Gas

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Balance at the beginning of the period (in Bbls/Mcf) | Mcf

4,939

Revisions of previous estimates (in Bbls/Mcf) | Mcf

^[1]

^[2]

(3,319)

^[3]

Improved recovery, extensions and discoveries (in Bbls/Mcf) | Mcf

Sales of minerals in place (in Bbls/Mcf) | Mcf

Production (sales volumes) (in Bbls/Mcf) | Mcf

(16)

(1,620)

Balance at the end of the period (in Bbls/Mcf) | Mcf

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves

Proved developed reserves (in Bbls/Mcf) | Mcf

4,939

Proved undeveloped reserves (in Bbls/Mcf) | Mcf

[1]	The positive crude oil revision resulted from better production performance during fiscal 2018. The negative NGL revision results primarily from lower expectations for ultimate NGL recoveries from the plant based on production data subsequent to the commencement of plant production.
[2]	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.
[3]	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.

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserves (Details) - USD ($)	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2015
Standardized measure of discounted future net cash flows
Future cash inflows	$ 521,533,765	$ 425,094,736	$ 383,491,193
Future production costs and severance taxes	(228,478,119)	(213,115,443)	(179,182,565)
Future development costs	(22,213,269)	(22,631,856)	(16,595,047)
Future income tax expenses	(50,810,883)	(47,055,551)	(45,713,438)
Future net cash flows	220,031,494	142,291,886	142,000,143
10% annual discount for estimated timing of cash flows	(101,073,080)	(59,354,333)	(64,042,824)
Standardized measure of discounted future net cash flows	$ 118,958,414	$ 82,937,553	$ 77,957,319	$ 159,196,539

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of NYMEX Prices Used in Determining Future Cash Flows (Details)	12 Months Ended
	Jun. 30, 2018 $ / bbl $ / MMBtu	Jun. 30, 2017 $ / bbl $ / MMBtu	Jun. 30, 2016 $ / bbl $ / MMBtu
Oil (per barrel)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices Used in Determining Future Cash Flows \| $ / bbl	57.50	48.85	42.91
Gas (per million BTU)
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Commodity Prices Used in Determining Future Cash Flows \| $ / MMBtu	0	0	0

Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Roll Forward of Changes in Standardized Measure of Discount Future Cash Flows on Proved Crude Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) - USD ($)	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves
Balance, beginning of year	$ 82,937,553	$ 77,957,319	$ 159,196,539
Net changes in sales prices and production costs related to future production	62,011,112	19,821,288	(120,832,747)
Changes in estimated future development costs	267,547	(1,626,833)	74,991
Sales of oil and gas produced during the period, net of production costs	(29,087,710)	(23,649,087)	(17,079,363)
Net change due to extensions, discoveries, and improved recovery	0	0	0
Net change due to revisions in quantity estimates	888,896	(2,206,287)	(18,821,014)
Net change due to sales of minerals in place	0	0	0
Development costs incurred during the period	0	2,632,547	16,327,883
Accretion of discount	11,089,455	10,086,904	21,870,650
Net change in discounted income taxes	871,540	(5,045,279)	36,598,239
Net changes in timing of production and other	(10,019,979)	4,966,981	622,141
Balance, end of year	$ 118,958,414	$ 82,937,553	$ 77,957,319

Selected Quarterly Financial Data (Unaudited) - Summary of Quarterly Financial Information (Details) - USD ($)	3 Months Ended								12 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2016
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 11,426,864	$ 10,249,566	$ 11,066,911	$ 8,537,871	$ 8,835,702	$ 9,525,437	$ 8,529,817	$ 7,593,940	$ 41,281,212	$ 34,484,896	$ 26,349,502
Operating income	5,182,663	3,663,267	4,829,252	2,536,459	2,583,912	3,893,236	3,675,381	2,727,593	16,211,641	12,880,122	1,665,187
Net income available to common shareholders	$ 4,532,750	$ 3,068,354	$ 9,876,848	$ 2,140,532	$ 1,500,761	$ 2,419,143	$ 2,307,634	$ 563,345	$ 19,618,484	$ 6,790,883	$ 23,986,060
Basic net income per share (in dollars per share)	$ 0.14	$ 0.09	$ 0.30	$ 0.06	$ 0.05	$ 0.07	$ 0.07	$ 0.02	$ 0.59	$ 0.21	$ 0.73
Diluted net income per share (in dollars per share)	$ 0.14	$ 0.09	$ 0.30	$ 0.06	$ 0.07	$ 0.07	$ 0.07	$ 0.05	$ 0.59	$ 0.21	$ 0.73

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04(19))
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Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=109260490&loc=d3e1337-109256

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
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-Section 55
-Paragraph 52
-URI http://asc.fasb.org/extlink&oid=109256448&loc=d3e4984-109258

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
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-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03(21))
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Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=109234566&loc=d3e22694-107794

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
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-Paragraph 1
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-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
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-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=109260490&loc=d3e1252-109256

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 220
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-04(23))
-URI http://asc.fasb.org/extlink&oid=114873765&loc=SL114874048-224260

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 60B
-Subparagraph (d)
-URI http://asc.fasb.org/extlink&oid=109260490&loc=SL5780133-109256

+ Details