View Filing Data

$ 27,841,265

$ 17,673,508

$ 21,349,920

Depreciation, depletion and amortization

3,615,737

1,228,685

1,300,207

Accretion of discount on asset retirement obligations

34,866

41,626

72,312

General and administrative expenses

^[1]

6,256,783

8,388,291

7,495,309

Restructuring charges

^[2]

(5,431)

1,293,186

Total operating costs

19,257,568

12,145,361

10,648,566

Income from operations

8,583,697

5,528,147

10,701,354

Other

(Loss) on derivative instruments, net

(109,974)

Interest income

35,991

30,256

22,580

Interest (expense)

(73,636)

(69,092)

(65,745)

Income before income tax provision

8,436,078

5,489,311

10,658,189

Income tax provision

3,444,221

1,891,998

4,029,761

Net income attributable to the Company

4,991,857

3,597,313

6,628,428

Dividends on preferred stock

674,302

Net income attributable to common shareholders

$ 4,317,555

$ 2,923,011

$ 5,954,126

Earnings per common share

Basic (in dollars per share)

$ 0.13

$ 0.09

$ 0.21

Diluted (in dollars per share)

$ 0.13

$ 0.09

$ 0.19

Weighted average number of common shares outstanding

Basic (in shares)

32,817,456

30,895,832

28,205,467

Diluted (in shares)

32,924,018

32,564,067

31,975,131

Delhi Field

Revenues

$ 27,573,641

$ 16,908,666

$ 19,219,036

Artificial Lift Technology

Production costs

8,516,323

Revenues

247,255

623,332

375,063

Production costs

743,802

609,221

390,238

Other Property

Revenues

20,369

141,510

1,755,821

Balance (in shares) at Jun. 30, 2012

Production costs

$ 95,488

$ 584,352

$ 1,390,500

[1]	General and administrative expenses for the years ended June 30, 2015, 2014 and 2013 included non-cash stock-based compensation expense of $943,653, $1,352,322, and $1,531,745, respectively.
[2]	Restructuring charges for the year ended June 30, 2014 included non-cash stock-based compensation expense of $376,365.

Consolidated Statements of Operations (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Non-cash stock-based compensation expense	$ 943,653	$ 1,352,322	$ 1,531,745
General and Administrative Expense
Non-cash stock-based compensation expense	943,653	1,352,322	$ 1,531,745
Restructuring Charges
Non-cash stock-based compensation expense	$ 376,365	$ 376,365

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
Consolidated Statements of Cash Flows - USD ($)	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Cash Flows From Operating Activities
Net income attributable to the Company	$ 4,991,857	$ 3,597,313	$ 6,628,428
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	3,664,373	1,272,778	1,341,055
Stock-based compensation	943,653	1,352,322	1,531,745
Stock-based compensation related to restructuring	0	376,365	0
Accretion of discount on asset retirement obligations	34,866	41,626	72,312
Settlement of asset retirement obligations	(223,564)	(315,952)	(90,531)
Deferred income taxes	1,422,489	1,344,812	2,512,978
Deferred rent	(17,145)	(17,145)	(17,146)
Loss on derivative instruments, net	109,974	0	0
Changes in operating assets and liabilities:
Receivables from oil and natural gas sales	(1,666,009)	176,707	(289,506)
Receivables from income taxes and other	748	281,822	(189,813)
Due from joint interest partners	0	49,063	47,088
Prepaid expenses and other current assets	378,049	(480,899)	(33,121)
Accounts payable and accrued expenses	551,452	663,645	278,436
Income taxes payable	190,032	(233,548)	141,581
Net cash provided by operating activities	10,380,775	8,108,909	11,933,506
Cash flows from investing activities
Proceeds from asset sales	398,242	542,347	3,479,976
Development of oil and natural gas properties	(4,890,909)	(966,931)	(4,163,080)
Acquisitions of oil and natural gas properties	0	(59,315)	(755,194)
Capital expenditures for technology and other equipment	(313,059)	(312,890)	0
Maturities of certificates of deposit	0	250,000	0
Other assets	(236,559)	(202,017)	(32,160)
Net cash used by investing activities	(5,042,285)	(748,806)	(1,470,458)
Cash flows from financing activities
Proceeds from the exercise of stock options	141,600	3,252,801	70,719
Acquisitions of treasury stock	(333,841)	(1,655,251)	(137,818)
Common stock dividends paid	(9,833,642)	(9,723,833)	0
Preferred stock dividends paid	(674,302)	(674,302)	(674,302)
Deferred loan costs	(94,075)	(63,535)	(16,211)
Tax benefits related to stock-based compensation	1,633,946	509,096	794,569
Other	67	6,850	32
Net cash provided (used) by financing activities	(9,160,247)	(8,348,174)	36,989
Net increase (decrease) in cash and cash equivalents	(3,821,757)	(988,071)	10,500,037
Cash and cash equivalents, beginning of year	23,940,514	24,928,585	14,428,548
Cash and cash equivalents, end of year	$ 20,118,757	$ 23,940,514	$ 24,928,585

Consolidated Statement of Changes in Stockholders' Equity - USD ($)

Total

Preferred

Common Stock

Additional Paid-in Capital

Retained Earnings

Treasury Stock

Balance at Jun. 30, 2012

$ 46,622,788

$ 317

$ 28,670

$ 29,416,914

$ 18,058,909

$ (882,022)

317,319

27,882,224

Increase (Decrease) in Stockholders' Equity

Issuance of restricted common stock

$ 211

(179)

Issuance of restricted common stock (shares)

211,197

Exercise of stock options

$ 70,719

$ 529

70,190

Exercise of stock options (shares)

550,000

529,237

Stock exchanged for payroll tax liabilities

$ (137,818)

(137,818)

Stock exchanged for payroll tax liabilities (in shares)

(13,689)

Stock-based compensation

1,531,745

794,569

Net income

6,628,428

Preferred stock cash dividends

(674,302)

Balance at Jun. 30, 2013

54,836,161

$ 317

$ 29,410

31,813,239

24,013,035

(1,019,840)

Balance (in shares) at Jun. 30, 2013

317,319

28,608,969

Increase (Decrease) in Stockholders' Equity

Issuance of restricted common stock

$ 40

(40)

Issuance of restricted common stock (shares)

39,732

Exercise of warrants

$ 905

(905)

Exercise of warrants (in shares)

905,391

Exercise of stock options

3,871,407

$ 3,299

3,868,108

Exercise of stock options (shares)

3,299,367

Forfeiture of restricted stock

$ (51)

Forfeiture of restricted stock (in shares)

(51,099)

Acquisitions of treasury stock

$ (2,273,857)

(2,273,857)

Acquisitions of treasury stock (shares)

(186,714)

Retirements of treasury stock

$ 0

$ (988)

(3,292,709)

3,293,697

Stock-based compensation

^[1]

1,728,687

509,096

Net income

3,597,313

Common stock cash dividends

(9,723,833)

Preferred stock cash dividends

(674,302)

Recovery of short swing profits

6,850

Balance at Jun. 30, 2014

51,877,522

$ 317

$ 32,615

34,632,377

17,212,213

Balance (in shares) at Jun. 30, 2014

317,319

32,615,646

Increase (Decrease) in Stockholders' Equity

Issuance of restricted common stock

$ 214

(147)

Issuance of restricted common stock (shares)

213,466

Exercise of stock options

$ 141,600

$ 87

141,513

Exercise of stock options (shares)

87,000

Acquisitions of treasury stock

$ (504,124)

(504,124)

Acquisitions of treasury stock (shares)

(70,907)

Retirements of treasury stock

$ (71)

(504,053)

504,124

Stock-based compensation

943,653

1,633,946

Net income

4,991,857

Common stock cash dividends

(9,833,642)

Preferred stock cash dividends

(674,302)

Balance at Jun. 30, 2015

$ 48,576,577

$ 317

$ 32,845

$ 36,847,289

$ 11,696,126

$ 0

Balance (in shares) at Jun. 30, 2015

317,319

32,845,205

[1]	Includes $376,365 of stock compensation reflected in restructuring charges.

Consolidated Statement of Changes in Stockholders' Equity (Parenthetical) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Non-cash stock-based compensation expense	$ 943,653	$ 1,352,322	$ 1,531,745
Restructuring Charges
Non-cash stock-based compensation expense	$ 376,365	$ 376,365

Organization and Basis of Preparation	12 Months Ended
Organization and Basis of Preparation	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Basis of Preparation	Organization and Basis of Preparation Nature of Operations. Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of oil and gas reserves within known oil and gas resources for our shareholders and customers utilizing conventional and proprietary technology. Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported income or stockholders' equity. Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Jun. 30, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents. Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2015 and 2014, no allowance for doubtful accounts was considered necessary. Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized. Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent, and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Test did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2015, 2014 or 2013. Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furniture and equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred. Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Fair Value of Financial Instruments.Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense. Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricing model to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fair value is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that the recipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service. Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment. Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations may generate revenues under several forms of operational or contractual arrangements. We have utilized the technology on wells that we develop and operate and on certain wells that we operate under farm-outs from other operators. In these cases, our revenues take the form of net sales of oil and gas production. We have also provided the technology to third parties under contractual arrangements that generate fees for the technology which are based on the net profits from oil and gas production. Under these contracts, we may be required to bear part or all of the incremental installation and capital costs for the technology. In other cases, we may be compensated for our technology through a fixed or variable fee per well, which does not require us to bear any net costs of installation or other capital costs. In the future, we may enter into licensing contracts which allow for the sale and installation of the technology by third parties to their customers or we may license the technology to larger organizations for use in specified geographic areas or on other broad terms. In all cases, we evaluate the substance of the contractual arrangement and recognize 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. In early June 2015, the Company initiated derivative transactions using costless collars to reduce its exposure to oil price volatility for a substantial portion of its forecasted production for the months of July 2015 through December 2015. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to a ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as a result of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes. Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computer equipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment. Intangible Assets - Intellectual Property. The Company capitalizes the external costs, consisting primarily of legal costs, related to securing its patents and trademarks. The costs related to patents are amortized over the remaining patent life which is less than the expected useful life of each patent. Trademarks are perpetual and are not amortized. Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense. Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common shares outstanding less any non-vested restricted common stock outstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants, and non-vested restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method. Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shall be assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPS computation. Potential dilutive common shares are excluded from the computation if their effect is anti-dilutive. Recent Accounting Pronouncements. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers: (Topic 606) to provide guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements. In April 2015, the FASB issued ASU 2015-03 (ASC Subtopic 835-30), Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The adoption of this new guidance will not have a material impact on the Company's consolidated financial statements and disclosures.

Receivables

12 Months Ended

Jun. 30, 2015

Receivables [Abstract]

Receivables

As of June 30, 2015 and June 30, 2014 our receivables consisted of the following:



	June 30, 2015		June 30, 2014
Receivables from oil and gas sales	$	3,122,155	$	1,456,146
Other	318		1,066
Total receivables	$	3,122,473	$	1,457,212

Prepaid Expenses and Other Current Assets

12 Months Ended

Jun. 30, 2015

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

Prepaid Expenses and Other Current Assets

As of June 30, 2015 and June 30, 2014 our prepaid expenses and other current assets consisted of the following:



	June 30, 2015		June 30, 2014
Prepaid insurance	$	178,994	$	169,288
Prepaid federal and state income taxes	22,542		419,999
Equipment inventory	81,538		85,888
Retainers and deposits	26,978		29,478
Other prepaid expenses	59,352		42,800
Prepaid expenses and other current assets	$	369,404	$	747,453

Property and Equipment

12 Months Ended

Jun. 30, 2015

Property, Plant and Equipment [Abstract]

Property and Equipment

As of June 30, 2015 and June 30, 2014, our oil and natural gas properties and other property and equipment consisted of the following:



	June 30, 2015			June 30, 2014
Oil and natural gas properties
Property costs subject to amortization	$	57,718,653		$	47,166,282
Less: Accumulated depreciation, depletion, and amortization	(12,531,767		)	(9,344,212		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	45,186,886			37,822,070
Other property and equipment
Furniture, fixtures and office equipment, at cost	287,680			343,178
Artificial lift technology equipment, at cost	319,994			377,943
Less: Accumulated depreciation	(330,918		)	(296,294		)
Other property and equipment, net	$	276,756		$	424,827

As of June 30, 2015 and 2014, all oil and gas property costs incurred by the Company were being amortized.

During the year ended June 30, 2014, we incurred $377,943 of costs related to the installation of our artificial lift technology, GARP^® on three wells of a five-well program for a third-party customer. Under the contract for these installations, we funded the majority of the incremental equipment and installation costs and receive 25% of the net profits from production, as defined, for as long as the technology remains in the wells.

During the year ended ended June 30, 2015, we incurred $217,733 of additional costs related to the installation on the remaining two wells of this five-well program. Also during the year ended June 30, 2015, we recorded an impairment charge of $275,682 reflecting the unrecovered installation costs of artificial lift equipment, net of estimated residual salvage value, which were associated with three wells of this third-party customer. Artificial lift equipment cost has been reduced by this impairment charge which is included in depreciation, depletion and amortization expense on our consolidated statement of operations.

On October 24, 2014, we sold all of our remaining mineral interest and assets in the Mississippi Lime project for proceeds of $389,165 and the buyer's assumption of all abandonment liabilities.

On December 1, 2013, we sold our producing assets and undeveloped reserves in the Lopez Field in South Texas in return for proceeds of $402,500 and the buyer's assumption of all abandonment liabilities.

The net proceeds from these sales, including the reduction of asset retirement obligations, were recognized as a reduction of the cost of oil and gas properties.

Other Assets

12 Months Ended

Jun. 30, 2015

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

Other Assets

AAs of June 30, 2015 and June 30, 2014 our other assets consisted of the following:



	June 30, 2015			June 30, 2014
Patent costs	538,276			305,592
Less: Accumulated amortization of patent costs	(47,063		)	(27,050		)
Deferred loan costs	337,078			243,003
Less: Accumulated amortization of deferred loan costs	(147,057		)	(98,421		)
Trademarks	44,803			40,928
Other assets, net	$	726,037		$	464,052

Restructuring

12 Months Ended

Jun. 30, 2015

Restructuring and Related Activities [Abstract]

Restructuring

On November 1, 2013, we undertook an initiative to refocus our business that resulted in an adjustment of our workforce with less emphasis on engineering and greater emphasis on sales and marketing. In exchange for severance and non-compete agreements with the terminated employees, we recorded a restructuring charge of $1,332,186 representing $376,365 of stock-based compensation from the accelerated vesting of equity awards and $955,821 of severance compensation and benefits to be paid during the twelve months ended December 31, 2014. All of the Company's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing the liability. Our disposition of the accrued restructuring charges is as follows:



Type of Cost	Balance at December 31, 2013		Payments			Adjustment to Cost			Balance at June 30, 2015
Salary continuation liability	$	615,721	$	(615,721	)	$	—		$	—
Incentive compensation costs	185,525		(185,525		)	—			—
Other benefit costs and employer taxes	154,575		(110,144		)	(44,431		)	—
Accrued restructuring charges	$	955,821	$	(911,390	)	$	(44,431	)	$	—

Accrued Liabilities and Other

12 Months Ended

Jun. 30, 2015

Other Liabilities Disclosure [Abstract]

Accrued Liabilities and Other

As of June 30, 2015 and June 30, 2014 our other current liabilities consisted of the following:



	June 30, 2015		June 30, 2014
Accrued incentive and other compensation	$	578,910	$	1,358,653
Accrued restructuring charges	—		530,412
Officer retirement costs	—		288,258
Asset retirement obligations due within one year	57,223		146,703
Accrued royalties, including suspended accounts	75,164		89,179
Accrued franchise taxes	94,885		87,575
Accrued - other	49,191		57,224
Accrued liabilities and other	$	855,373	$	2,558,004

Asset Retirement Obligations

12 Months Ended

Jun. 30, 2015

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 obligation for the years ended June 30, 2015 and 2014:



	Years Ended
	2015			2014
Asset retirement obligations—beginning of period	$	352,215		$	615,551
Liabilities incurred (1)	564,019			—
Liabilities settled	(137,604		)	(323,665		)
Liabilities sold	(52,526		)	(48,273		)
Accretion of discount	34,866			41,626
Revisions to previous estimates	12,020			66,976
Less: current asset retirement obligations	(57,223		)	(146,703		)
Asset retirement obligations—end of period	$	715,767		$	205,512


(1)	Primarily attributable to the reversion of our working interest in the Delhi Field in November 2014.

Stockholders' Equity	12 Months Ended
Stockholders' Equity	Jun. 30, 2015
Equity [Abstract]
Stockholders' Equity	Stockholders' Equity Common Stock During the year ended June 30, 2014, we issued (i) 1,568,832 shares of our common stock upon the exercise of incentive stock options (ISOs), receiving cash proceeds totaling $3,252,801, and (ii) 2,635,696 of our common shares upon cashless exercises of nonqualified stock options ("NQSOs") and incentive warrants, all being exercised on a net basis, except for 50,956 of previously acquired shares owned by option holders that were swapped in payment of the exercise price. The weighted average cost of these swapped shares was $12.14. In fiscal 2014, we retired 801,889 shares of treasury stock acquired in previous fiscal years at a cost of $1,019,840 and 186,714 treasury shares acquired during fiscal 2014 from employees and directors at an average cost of $12.18 per share or $2,273,857. The shares acquired in 2014 were received in satisfaction of payroll tax liabilities from the exercise of stock options and vesting of restricted stock (requiring cash outlays by us) and 50,956 shares were received from option holders in cashless stock option exercises, using stock previously owned by the option holder. Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. We paid cash dividends of $9,833,642 and $9,723,833 from retained earnings to our common shareholders during the years ended June 30, 2015, and 2014, respectively. On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5,000,000 of the Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will depend upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time. Payment for shares repurchased under the program will be funded using the Company's working capital. The Company intends to retire the repurchased shares. As of June 30, 2015, the Company had purchases of 63,372 shares of stock which had a weighted average price per share of $6.87. During fiscal 2015, the Company also acquired 7,535 shares of its common stock at a weighted average price per share of $9.16 in exchange for payroll tax liabilities related to stock-based compensation. Series A Cumulative Perpetual Preferred Stock During the year ended June 30, 2012, we sold 317,319 shares of our 8.5% Series A Cumulative (perpetual) Preferred Stock at a weighted average sales price of $23.80 per share, with a liquidation preference of $25.00 per share. All shares were underwritten or sold through McNicoll Lewis & Vlak LLC (MLV), 220,000 of which were sold in an underwritten public offering and 97,319 shares of which were sold under an at-the-market sales agreement ("ATM"), providing aggregate net proceeds of $6,930,535 after market discounts, underwriting fees, legal and other expenses of the offerings. The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to holders thereof. Optional redemption can be made by us at any time after July 1, 2014 for the stated liquidation value of $25.00 per share plus accrued dividends. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common shareholders, but subordinate to any of our existing and future debt. Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors. We paid dividends of $674,302, $674,302 and $674,302 to holders of our Series A Preferred Stock during the years ended June 30, 2015, 2014 and 2013, respectively. Expected Tax Treatment of Dividends to Recipients Based on our current projections for the fiscal year ending June 30, 2015, we expect preferred dividends will be treated as qualified dividend income to recipients and that a portion of our cash dividends on common stock will be treated as a return of capital and the remainder as qualified dividend income. We will make a preliminary determination regarding the tax treatment of dividends for the current fiscal year when we report this information to recipients. As a result of the difference between our June 30 fiscal year and the calendar year basis of our dividend reporting requirements, it is possible that we will be required to amend these reports when our final taxable income for the fiscal year is determined, as this will potentially affect the tax status of our dividends to recipients. For the fiscal year ended June 30, 2014, cash dividends on preferred and common stock were treated for tax purposes as a return of capital to our stockholders.

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

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(d),(e))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21484-112644

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 310
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB TOPIC 4.E)
-URI http://asc.fasb.org/extlink&oid=27010918&loc=d3e74512-122707

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21488-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187143-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21463-112644

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

+ Details

Stock-Based Incentive Plan

12 Months Ended

Jun. 30, 2015

Stock-Based Incentive Plan

We have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company under the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"). The Plan authorized the issuance of 6,500,000 shares of common stock. As of June 30, 2015, 542,529 shares remain available for grant.

Stock Options and Incentive Warrants

No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. No Incentive Warrants have been granted since February 2006, all compensation costs attributable to these awards have been recognized in prior periods and all remaining outstanding awards were exercised in November 2013.

The following summary presents information regarding outstanding Stock Options as of June 30, 2015, and the changes during the fiscal year:



	Number of Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value(1)		Weighted Average Remaining Contractual Term (in years)
Stock Options outstanding at June 30, 2014	178,061		$	2.08
Granted	—		—
Exercised	(87,000	)	$	1.63
Canceled or forfeited	—		—
Expired	—		—
Stock Options outstanding at June 30, 2015	91,061		$	2.50	$	372,000	1.3
Vested or expected to vest at June 30, 2015	91,061		$	2.50	$	372,000	1.3
Exercisable at June 30, 2015	91,061		$	2.50	$	372,000	1.3


(1)	Based upon the difference between the market price of our common stock on the last trading date of the period ($6.59 as of June 30, 2015) and the Stock Option exercise price of in-the-money Stock Option.

For the year ended June 30, 2015, there were 87,000 Stock Options exercised with an aggregate intrinsic value of $501,810. For the year ended June 30, 2014, there were 4,644,759 Stock Options and Incentive Warrants exercised, with an aggregate intrinsic value of $47,504,114. For the year ended June 30, 2013, there were 550,000 Stock Options exercised with an aggregate intrinsic value of $5,233,480.

During the years ended June 30, 2015, 2014, and 2013, there were 0, 0, and 18,922 Stock Options that vested with a total grant date fair value of $0, $0, and $46,359, respectively.

Restricted Stock and Contingent Restricted Stock

Prior to fiscal 2015 all Restricted Stock grants contained a four-year vesting period period based solely on service. During fiscal 2015, the Company awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were issued on the date of grant, whereas the Contingent Restricted Stock will be issued only upon the attainment of specified performance-based or market-based vesting provisions.

Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Fair values for these market-based awards ranged from $4.26 to $8.40 with expected vesting periods of 3.30 to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2015:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2015 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at June 30, 2014	140,067		$	8.70	$	—
Service-based awards granted	100,910		9.53
Performance-based awards granted	76,642		10.05
Market-based awards granted	35,914		7.59
Vested	(91,306	)	8.40
Forfeited	—		—
Unvested at June 30, 2015	262,227		$	9.37	$	1,306,990	2.3


(1)	Excludes $770,252 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

During the years ended June 30, 2015, 2014, and 2013, there were 91,306, 277,198, and 277,198 shares of Restricted Stock that vested with a total grant date fair value of $766,970, $1,796,243, and $1,427,570, respectively.

The following table summarizes Contingent Restricted Stock activity:



	Number of Restricted Stock Units	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2015 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014	—	—
Performance-based awards granted	38,325	$	10.05	$	—
Market-based awards granted	17,961	4.26		—
Unvested at June 30, 2015	56,286	$	8.20	$	57,004	2.5

(1) Excludes $385,166 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Stock-based Compensation Expense

For the years ended June 30, 2015, 2014, and 2013, we recognized stock-based compensation expense related to Restricted Stock, Contingent Restricted Stock grants, and Stock Option grants of $962,813, $1,728,687, and $1,531,745, respectively. For the year ended June 30, 2015, this expense includes $19,160 of cash dividends paid on unvested performance-based awards for which vesting is not considered probable at this time for accounting purposes. See Note 7 – Restructuring, for stock compensation included in Restructuring Charges recorded at December 31, 2014.

Supplemental Disclosure of Cash Flow Information

12 Months Ended

Jun. 30, 2015

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosure of Cash Flow Information

Our supplemental disclosures of cash flow information for the years ended June 30, 2015, 2014, and 2013 are as follows:



	June 30,
	2015		2014			2013
Income taxes paid	$	220,000	$	755,941		$	699,874
Income tax refunds	331,733		—			—
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	5,422,566		(183,766		)	(1,535,322		)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	576,039		66,976			65,575
Accrued purchases of treasury stock	170,283		—			—
Previously acquired Company shares swapped by holders to pay stock option exercise price	$	—	$	618,606		$	—

Income Taxes

12 Months Ended

Jun. 30, 2015

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, 2015, 2014 and 2013. 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, 2012 through June 30, 2014 for federal tax purposes and for the years ended June 30, 2011 through June 30, 2014 for state tax purposes.

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



	June 30, 2015		June 30, 2014		June 30, 2013
Current:
Federal	$	1,413,296	$	386,018	$	857,480
State	608,436		161,168		659,303
Total current income tax provision	2,021,732		547,186		1,516,783
Deferred:
Federal	1,282,059		1,319,727		2,546,495
State	140,430		25,085		(33,517		)
Total deferred income tax provision	1,422,489		1,344,812		2,512,978
	$	3,444,221	$	1,891,998	$	4,029,761

The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate, currently 34%, to the income tax provision in our financial statements. The effective tax rate for all years is in excess of the statutory rate as a result of state income taxes, primarily in the state of Louisiana, with smaller adjustments related to stock-based compensation and other permanent differences.



	June 30, 2015			June 30, 2014			June 30, 2013
Income tax provision (benefit) computed at the statutory federal rate:	$	2,868,267		$	1,866,366		$	3,623,784
Reconciling items:
State income taxes, net of federal tax benefit	595,708			189,081			413,019
Permanent differences related to stock-based compensation	—			(155,817		)	8,933
Expiring NOLs related to 2004 reverse merger	—			—			600,964
Deferred tax asset valuation adjustment	—			—			(600,964		)
Other permanent differences	(19,754		)	(7,632		)	(15,975		)
Income tax provision	$	3,444,221		$	1,891,998		$	4,029,761

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are classified as either current or noncurrent on the balance sheet based on the classification of the related asset or liability for financial reporting purposes. Deferred tax assets and liabilities not related to specific assets or liabilities on the financial statements are classified according the expected reversal date of the temporary difference or the expected utilization date for tax attribute carryforwards. The change in the NOLs is primarily due to expiring NOLs related to the 2004 reverse merger as well as utilization of NOLs to offset potential current year taxable income. The components of our deferred taxes are detailed in the table below:



	June 30, 2015			June 30, 2014			June 30, 2013
Deferred tax assets:
Non-qualified stock-based compensation	$	173,647		$	134,469		$	774,673
Net operating loss carry-forwards	400,288			427,249			427,249
AMT credit carry-forward*	701,254			701,254			502,466
Other	91,113			165,775			28,170
Gross deferred tax assets	1,366,302			1,428,747			1,732,558
Valuation allowance	(292,446		)	(292,446		)	(292,446		)
Total deferred tax assets	1,073,856			1,136,301			1,440,112
Deferred tax liability:
Oil and natural gas properties	(12,233,993		)	(10,873,949		)	(9,832,948		)
Total deferred tax liability	(12,233,993		)	(10,873,949		)	(9,832,948		)
Net deferred tax liability	$	(11,160,137	)	$	(9,737,648	)	$	(8,392,836	)

_______________________________________________________________________________


*	Total AMT credit carry-forward is $901,545. Our net deferred tax liability does not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation.

As of June 30, 2015, we have a federal tax loss carryforward of approximately $25.8 million, 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, and $1.2 million of remaining tax loss carryforwards that we acquired through the reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger have 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.

The remaining fiscal 2014 tax loss carry-forward of $24.6 million and future tax benefits resulting from the fiscal 2014 exercises will not affect our future tax provision for financial reporting purposes, nor are we able to recognize a deferred tax asset for these future benefits. When we receive these tax benefits as a reduction of future cash taxes that would otherwise be payable, we will recognize that benefit as an increase in additional paid in capital.

Based on the carryback of tax losses resulting from the exercise of stock options and incentive warrants in fiscal 2014, we filed a request for refund of cash taxes paid in Louisiana for the previous three fiscal years totaling approximately $1.5 million. This refund will not affect our tax provision for financial reporting purposes. When and if received, we will recognize the benefit as an increase in additional paid-in capital. We cannot be certain of the timing or amount of the refund if any. As a result, this potential refund has not been reflected in the accompanying financial statements. This carryback, if realized, will utilize approximately $19.0 million of an estimated $24.2 million net loss for state tax purposes with another $3.8 million expected to be used to offset taxable income in 2015, leaving $1.5 million of tax loss carryforwards remaining for Louisiana tax purposes.

In addition, as of June 30, 2015, the Company has an estimated carryforward of percentage depletion in excess of basis of approximately $11.6 million. These future deductions are limited to 65% of taxable income in any period.

Related Party Transactions	12 Months Ended
Related Party Transactions	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions On June 30, 2011, we entered into a Technology Assignment Agreement with the Company’s Senior Vice President of Operations to acquire exclusive, perpetual, non-cancelable rights to the patented GARP^® technology he developed while employed by the Company. Under the agreement, he is paid a fee when the technology is employed. For the years ended June 30, 2015, 2014 and 2013, we made payments of $26,579, $10,113 and $10,113, respectively, under the agreement.

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

Commitments and Contingencies Disclosure [Abstract]

Net Income Per Share

12 Months Ended

Jun. 30, 2015

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,
	2015		2014		2013
Numerator
Net income attributable to common shareholders	$	4,317,555	$	2,923,011	$	5,954,126
Denominator
Weighted average number of common shares—Basic	32,817,456		30,895,832		28,205,467
Effect of dilutive securities:
Contingent restricted stock grants	4,422		—		—
Common stock warrants issued in connection with equity and financing transactions	—		—		878
Stock Options and Incentive Warrants	102,140		1,668,235		3,768,786
Total weighted average dilutive securities	106,562		1,668,235		3,769,664
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	32,924,018		32,564,067		31,975,131
Net income per common share—Basic	$	0.13	$	0.09	$	0.21
Net income per common share—Diluted	$	0.13	$	0.09	$	0.19

The following are reflected in the calculation of diluted earnings per share as of June 30, 2015:



Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2015
Contingent Restricted Stock grants	$	—	17,961
Stock Options	2.50		91,061
Total	$	2.09	109,022

The following are reflected in the calculation of diluted earnings per share as of June 30, 2014:

The following are reflected in the calculation of diluted earnings per share as of June 30, 2013:



Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2013
Common stock warrants issued in connection with equity and financing transactions	$	2.50	1,165
Stock Options and Incentive Warrants	1.99		4,822,820
Total	$	1.99	4,823,985

Unsecured Revolving Credit Agreement	12 Months Ended
Unsecured Revolving Credit Agreement	Jun. 30, 2015
Debt Disclosure [Abstract]
Unsecured Revolving Credit Agreement	Unsecured Revolving Credit Agreement On February 29, 2012, Evolution Petroleum Corporation entered into a Credit Agreement (the "Credit Agreement") with Texas Capital Bank, N.A. (the "Lender"). The Credit Agreement provides the Company with a revolving credit facility (the "facility") in an amount up to $50,000,000 with availability governed by an Initial Borrowing Base of $5,000,000. A portion of the facility not in excess of $1,000,000 is available for the issuance of letters of credit. The facility is unsecured and has a term of four years, expiring on February 29, 2016. The Company's subsidiaries guarantee the Company's obligations under the facility. The proceeds of any loans under the facility are to be used by the Company for the acquisition and development of oil and gas properties, as defined in the facility, the issuance of letters of credit, and for working capital and general corporate purposes. Semi-annually, the borrowing base and a monthly reduction amount are re-determined from reserve reports. Requests by the Company to increase the $5,000,000 initial amount are subject to the Lender's credit approval process, and are also limited to 25% of the value our oil and gas properties, as defined. At the Company's option, borrowings under the facility bear interest at a rate of either (i) an Adjusted LIBOR rate (LIBOR rate divided by the remainder of 1 less the Lender's Regulation D reserve requirement), or (ii) an adjusted Base Rate equal to the greater of the Lender's prime rate or the sum of 0.50% plus the Federal Fund Rate. A maximum of three LIBOR based loans can be outstanding at any time. Allowed loan interest periods are one, two, three and six months. LIBOR interest is payable at the end of the interest period except for six-month loans for which accrued interest is payable at three months and at end of term. Base Rate interest is payable monthly. Letters of credit bear fees of 3.5% per annum rate applied to the principal amount and are due when transacted. The maximum term of letters of credit is one year. A commitment fee of 0.50% per annum accrues on unutilized availability and is payable quarterly. The Company is responsible for certain administrative expenses of the Lender over the life of the Credit Agreement as well as $50,000 in loan costs incurred upon closing. The Credit Agreement also contains financial covenants including a requirement that the Company maintain a current ratio of not less than 1.5 to 1; a ratio of total funded Indebtedness to EBITDA of not more than 2.5 to 1, and a ratio of EBITDA to interest expense of not less than 3 to 1. The agreement specifies certain customary covenants, including restrictions on the Company and its subsidiaries from pledging their assets, incurring defined Indebtedness outside of the facility other than permitted indebtedness, and it restricts certain asset sales. Payments of dividends for the Series A Preferred are only restricted by the EBITDA to interest coverage ratio, wherein such dividends are a 1X deduction from EBITDA (as opposed to a 3:1 requirement if dividends were treated as interest expense). The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the Lender may declare any amounts outstanding under the Credit Agreement to be immediately due and payable. As of June 30, 2015 and 2014, the Company had no borrowings and no outstanding letters of credit issued under the facility, resulting in an available borrowing base capacity of $5,000,000, and we are in compliance with all the covenants of the Credit Agreement. During early 2014 the Lender waived the provisions of the Credit Agreement pertaining to the past payments of cash dividends on our common stock, and the Credit Agreement was amended to permit the payment of cash dividends on common stock in the future if no borrowings are outstanding at the time of such payment. In connection with this agreement the Company incurred $179,468 of debt issuance costs, which have been capitalized in Other Assets and are being amortized on a straight-line basis over the term of the agreement. The unamortized balance in debt issuance costs related to the Credit Agreement was $32,411 as of June 30, 2015. The Company is in discussions with the Lender and other financial institutions to replace the unsecured Credit Agreement with an expanded secured facility. As of June 30, 2015, the Company had incurred approximately $157,610 in legal and title costs related to this proposed new agreement, which are also capitalized in Other Assets.

Commitments and Contingencies

12 Months Ended

Jun. 30, 2015

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.

The Company and its wholly-owned subsidiary NGS Sub Corp. are defendants in a lawsuit brought by John C. McCarthy et al in the fifth District Court of Richland Parish, Louisiana in July 2011. The plaintiffs alleged, among other claims, that we fraudulently and wrongfully purchased plaintiffs’ income royalty rights in the Delhi Field Unit in the Holt-Bryant Reservoir in May 2006. The plaintiffs are seeking cancellation of the transaction and monetary damages. On March 29, 2012, the Fifth District Court dismissed the case against the Company and NGS Sub Corp. The Court found that plaintiffs had “no cause of action” under Louisiana law, assuming that the Plaintiffs’ claims were valid on their face. Plaintiffs filed an appeal and the Louisiana Second Circuit Court of Appeal affirmed the dismissal, but allowed the plaintiffs to amend their petition to state a different possible cause of action. The plaintiffs amended their claim and re-filed with the district court. We subsequently filed a second motion pleading “no cause of action,” with which the district court again agreed and dismissed the plaintiffs’ case on September 23, 2013. Plaintiffs again filed an appeal in November 2013. In October 2014, the appellate court reversed the district court. We subsequently filed for a rehearing which was denied. We now have filed an Application for Writ of Review in the Louisiana Supreme Court in which we have asked the Louisiana Supreme Court to reverse the appellate court and reinstate the trial court judgment dismissing plaintiffs’ case. Amicus Curiae Briefs have been filed in support of the writ application by the Louisiana Oil & Gas Association, the Louisiana Mid-Continent Oil and Gas Association and the American Association of Professional Landmen. Our brief and supporting Amicus Curiae Briefs have been filed. Oral arguments were heard on September 1, 2015. Counsel has advised us that, based on developments in the case to date, the risk of a material loss in this matter is remote.

As previously reported, on August 23, 2012, we and our wholly-owned subsidiary, NGS Sub Corp., and Robert S. Herlin, our Chief Executive Officer, were served with a lawsuit filed in federal court by James H. and Kristy S. Jones (the “Jones lawsuit”) in the Western District Court of the Monroe Division, Louisiana. The plaintiffs alleged primarily that we (defendants) wrongfully purchased the plaintiffs’ 4.8119% overriding royalty interest in the Delhi Unit in January 2006 by failing to divulge the existence of an alleged previous agreement to develop the Delhi Field for enhanced oil recovery. The plaintiffs were seeking rescission of the assignment of the overriding royalty interest and monetary damages. We believed that the claims were without merit and not timely, and we vigorously defended against the claims. We filed a motion to dismiss for failure to state a claim under Federal Rule of Civil Procedure 12(b) (6) on April 1, 2013. On September 17, 2013, the federal court in the Western District Court of the Monroe Division, Louisiana, dismissed a portion of the claims and allowed the plaintiffs to pursue the remaining portion of the claims. Our motion to dismiss was for lack of cause of action, assuming that the plaintiffs' claims were valid on their face. On September 25, 2013, plaintiff Jones filed a motion to alter or amend the September 17, 2013 judgment. On December 27, 2013, the court denied said plaintiffs’ motion, and on January 21, 2014, we filed a motion to reconsider the nondismissal of the remaining claims, which was denied. The Court entered a Scheduling Order setting trial of the case for the week of June 15, 2015. Subsequent to depositions of the plaintiffs, in late March 2015, in the United States District Court for the Western District of Louisiana Monroe Division, a joint motion to dismiss with prejudice was entered into by all parties in the lawsuit and the judge signed the judgment of dismissal with prejudice. Further, no compensation or other consideration was paid or provided to the plaintiffs by any of the defendants other than an agreement by us not to sue for malicious prosecution or defamation, or seek sanctions, and the plaintiffs agreed to relinquish any and all claims to the 4.8119% overriding royalty interest in the Delhi Unit.

On December 13, 2013, we and our wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp., filed a lawsuit in the 133^rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi Field in Richland Parish, Louisiana. The specific allegations include improperly charging the payout account for capital expenditures and costs of capital, failure to adhere to preferential rights to participate in acquisitions within the defined area of mutual interest, breach of the promises to assume environmental liabilities and fully indemnify us from such costs, and other breaches. We also alleged that Denbury’s gross negligence caused certain environmental damage to the unit. Specifically, we allege that Denbury failed to properly conduct CO² injection activities. We are seeking declaration of the validity of the 2006 agreements and recovery of damages and attorneys’ fees. Denbury subsequently filed counterclaims, including the assertion that we owe Denbury additional revenue interests pursuant to the 2006 agreements and that our transfers of the reversionary interests from our wholly owned subsidiary to our parent corporation and subsequently to another wholly-owned subsidiary were not timely noticed to Denbury. We subsequently amended and expanded our claims. The Company disagrees with, and is vigorously defending against, Denbury's counterclaims. This matter is scheduled for trial in April of 2016.

On January 26, 2015, Denbury notified us it had withheld and suspended 2.891545% of our overriding royalty revenue interest in the field for the months of November and December 2014. This unilateral suspension of a portion of our overriding royalties by the operator was made without consultation with the Company and, we believe, was without legal basis. On February 26, 2015, we and Denbury executed an agreement under which Denbury agreed to reverse the previously disclosed suspension of our overriding royalty interest revenues and release to Evolution amounts previously suspended totaling approximately $712,000. Denbury further agreed not to suspend any future revenues attributable to any of our revenue interests, except under limited circumstances, such as non-payment of joint interest billings. This agreement did not settle any of the outstanding litigation matters with Denbury, including their counterclaim related to the net revenue interest conveyed in the 2006 Purchase and Sale Agreement.

Lease Commitments. We have a non-cancelable operating lease for office space that expires on July 31, 2016. Future minimum lease commitments as of June 30, 2015 under this operating lease are as follows:



For the fiscal year ended June 30,
2016	$	159,011
2017	13,251
Total	$	172,262

Rent expense for the years ended June 30, 2015, 2014, and 2013 was $175,103, $174,229, and $147,233, respectively.

Employment Contracts. We have entered into employment agreements with two of the Company's senior executives. The employment contracts provide for severance payments in the event of termination by the Company for any reason other than cause or permanent disability, or in the event of a constructive termination, as defined. The agreements provide for the payment of base pay and certain medical and disability benefits for periods ranging form 6 months to 1 year after termination. The total contingent obligations under the employment contracts as of June 30, 2015 was approximately $473,000.

Concentrations of Credit Risk

12 Months Ended

Jun. 30, 2015

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 accepting terms under the Delhi operator's agreement with Plains Marketing L.P. for the delivery and pricing of our oil there. The majority of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more our net oil and natural gas revenues during the years ended June 30, 2015, 2014, and 2013. 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	2015		2014		2013
Plains Marketing L.P. (includes Delhi production)	99	%	96	%	90	%
Enterprise Crude Oil LLC	—	%	2	%	4	%
Flint Hills	—	%	1	%	2	%
ETC Texas Pipeline, LTD.	—	%	1	%	—	%
All others	1	%	—	%	4	%
Total	100	%	100	%	100	%

Accounts Receivable. Substantially all of our accounts receivable result from uncollateralized oil and natural gas sales to third parties in the oil and natural gas industry. This concentration of customers may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

Cash and Cash Equivalents and Certificates of Deposit. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents in high quality money market funds. At times, cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation ("FDIC"). Our certificates of deposit are below or at the maximum federally insured limit set by the FDIC.

Retirement Plan	12 Months Ended
Retirement Plan	Jun. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Retirement Plan	Retirement Plan Effective February 1, 2007, we implemented a 401(k) Savings 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 compensation, with Company contributions fully vested when made. Our matching contributions to the Savings Plan totaled $85,676, $116,873, and $89,810 for the years ended June 30, 2015, 2014, and 2013, respectively.

Derivatives

12 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

In early June 2015, the Company began using derivative instruments to reduce its exposure to oil price volatility for a substantial portion of its forecasted production for the months of July 2015 through December 2015 to achieve a more predictable level of cash flows to support the Company’s capital expenditure program. The costless collars the Company uses to manage risk are designed to establish floor and ceiling prices on anticipated future oil production. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not enter into derivative instruments for speculative or trading purposes.

These derivative instruments can result in both fair value asset and liability positions held with that counterparty, which positions are all offset to a single fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value of derivative instruments where the Company is in a net liability position with its counterparty as of June 30, 2015 totaled $109,974. Refer to Note 21—Fair Value Measurement for derivative asset and derivative liability balances before offsetting.

The Company monitors the credit rating of its counterparty, Cargill, Incorporated, and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparty 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 counterparty to its derivative instruments.

The Company's collateral obligations are met by a credit line of $5,000,000 provided by the counterparty during the first ninety days of the agreement and thereafter by the Company which is seeking a secured facility to fund collateral obligations.

For the year ended June 30, 2015, the Company recorded in the consolidated statement of operations a loss on unsettled derivatives, net of $109,974.

The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2015.



Period	Type of Contract	Volumes (in Bbls./day)	Weighted Average Floor Price per Bbl.	Weighted Average Ceiling Price per Bbl.	Weighted Average Collar Spread per Bbl.
Months of July 2015 through December 2015	Costless Collar	1,100	$55.00	$64.05	$9.05

Subsequent to June 30, 2015, the Company realized gains of $138,787 and $412,985 on derivative contracts expiring in July 2015 and August 2015, respectively.

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41641-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurement

12 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurement

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

The three levels are defined as follows:

Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair Value of Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2015. All items included in the tables below are Level 2 inputs within the fair value hierarchy:



	June 30, 2015
Asset (Liability)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts Presented in the Consolidated Balance Sheets
Current derivative assets	$	355,555		$	(355,555	)	$	—
Current derivative liabilities	(465,529		)	355,555			(109,974		)
Total	$	(109,974	)	$	—		$	(109,974	)

The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparty's credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values.

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

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

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

12 Months Ended

Jun. 30, 2015

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 $576,039, $66,976 and $65,575 during the years ended June 30, 2015, 2014, and 2013, respectively.



	For the Years Ended June 30,
	2015		2014		2013
Oil and natural gas activities
Property acquisition costs:
Proved property	$	—	$	—	$	26,449
Unproved property	—		47,344		195,599
Exploration costs	—		757,423		4,356,640
Development costs	10,975,637		18,566		79,035
Total costs incurred for oil and natural gas activities	$	10,975,637	$	823,333	$	4,657,723

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, 2015, 2014, and 2013, 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, 2012	11,638,618		492,473		7,860,156		13,441,116
Revisions of previous estimates (a)	1,826,053		975,515		27,679		2,806,181
Sales of minerals in place	(485,536	)	(480,832	)	(7,726,032	)	(2,254,038	)
Production (sales volumes)	(196,380	)	(7,271	)	(139,006	)	(226,819	)
June 30, 2013	12,782,755		979,885		22,797		13,766,440
Revisions of previous estimates (b)	(1,919,052	)	1,269,588		2,412,677		(247,350	)
Improved recovery, extensions and discoveries	17,146		32,731		498,044		132,884
Sales of minerals in place	(184,722	)	—		—		(184,722	)
Production (sales volumes)	(169,783	)	(3,516	)	(26,655	)	(177,742	)
June 30, 2014	10,526,344		2,278,688		2,906,863		13,289,510
Revisions of previous estimates (c)	(64,074	)	156,195		(2,894,703	)	(390,330	)
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(450,294	)	(1,288	)	(7,221	)	(452,786	)
June 30, 2015	10,011,976		2,433,595		4,939		12,446,394
Proved developed reserves:
June 30, 2012	7,670,934		111,978		1,499,382		8,032,809
June 30, 2013	10,077,522		8,539		22,797		10,089,861
June 30, 2014	7,858,224		32,164		481,042		7,970,562
June 30, 2015	7,347,231		1,572		4,939		7,349,626
Proved undeveloped reserves:
June 30, 2012	3,967,684		380,495		6,360,774		5,408,307
June 30, 2013	2,705,233		971,346		—		3,676,579
June 30, 2014	2,668,120		2,246,524		2,425,821		5,318,948
June 30, 2015	2,664,745		2,432,023		—		5,096,768

(a) A significant upward reserve revision occurred in the Delhi Field during fiscal 2013 as a result of (1) revised geological maps based on production results and acquired seismic data, (2) inclusion of an additional reservoir with similar features, production history and suitability for EOR, and (3) inclusion of natural gas processing at Delhi.

(b) Significant reserve revisions occurred in the Delhi Field during fiscal 2014. As a result of an adverse fluid release event in the Field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO₂ injections in certain parts of the Field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the gas plant in the Delhi Field. The plant is expected to significantly increase recoveries of these products, particularly natural gas, which was not previously planned to be extracted from the injection volumes.

(c) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi Field gas plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to excessive formation solids that kept interfering with pumping. The gas plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned gas plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well.

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, Disclosures about Oil and Gas Producing Activities ("ASC 932"). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves.

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2015, 2014, and 2013 are as follows:



	For the Years Ended June 30,
	2015			2014			2013
Future cash inflows	$	807,030,282		$	1,193,515,075		$	1,436,980,607
Future production costs and severance taxes	(309,225,333		)	(475,387,931		)	(510,902,614		)
Future development costs	(49,691,006		)	(46,154,178		)	(60,742,406		)
Future income tax expenses	(123,888,665		)	(195,581,510		)	(275,113,560		)
Future net cash flows	324,225,278			476,391,456			590,222,027
10% annual discount for estimated timing of cash flows	(165,028,739		)	(250,313,784		)	(283,001,328		)
Standardized measure of discounted future net cash flows	$	159,196,539		$	226,077,672		$	307,220,699

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials.



	Year Ended June 30,
	2015				2014				2013
	Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	71.88	$	3.44	$	100.37	$	4.10	$	91.51	$	3.44

The NGL price utilized for future cash inflows was based on the historical price received.

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,
	2015			2014			2013
Balance, beginning of year	$	226,077,672		$	307,220,699		$	283,597,493
Net changes in sales prices and production costs related to future production	(88,043,095		)	(73,439,526		)	(35,184,725		)
Changes in estimated future development costs	(9,585,405		)	9,848,614			(566,125		)
Sales of oil and gas produced during the period, net of production costs	(18,538,016		)	(16,479,934		)	(19,569,182		)
Net change due to extensions, discoveries, and improved recovery	—			775,574			—
Net change due to revisions in quantity estimates	(9,391,321		)	(23,757,788		)	64,817,544
Net change due to sales of minerals in place	—			(3,150,277		)	(34,119,027		)
Development costs incurred during the period	7,785,095			—			747,656
Accretion of discount	31,974,540			45,896,187			41,678,733
Net change in discounted income taxes	34,157,767			58,073,450			10,175,957
Net changes in timing of production and other (a)	(15,240,698		)	(78,909,327		)	(4,357,625		)
Balance, end of year	$	159,196,539		$	226,077,672		$	307,220,699

(a) Due to the June 2013 adverse fluid release event in the Delhi Field, the operator had expressed plans to produce the Delhi Field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014.

Selected Quarterly Financial Data (Unaudited)

12 Months Ended

Jun. 30, 2015

Quarterly Financial Information Disclosure [Abstract]

Selected Quarterly Financial Data (Unaudited)

The following table presents summarized quarterly financial information for the years ended June 30, 2015 and 2014:



2015	First		Second (1)		Third		Fourth
Revenues	$	4,004,827	$	7,708,067	$	7,064,689	$	9,063,682
Operating income	1,840,866		2,162,294		1,245,990		3,334,547
Net income available to common shareholders	$	960,435	$	1,071,342	$	566,011	$	1,719,767
Basic net income per share	$	0.03	$	0.03	$	0.02	$	0.05
Diluted net income per share	$	0.03	$	0.03	$	0.02	$	0.05



2014	First		Second (2)			Third (3)		Fourth
Revenues	$	4,633,699	$	4,392,289		$	4,337,006	$	4,310,514
Operating income (loss)	1,963,897		(158,095		)	1,357,534		2,364,811
Net income (loss) available to common shareholders	$	1,303,876	$	(577,459	)	$	755,125	$	1,441,469
Basic net income (loss) per share	$	0.05	$	(0.02	)	$	0.02	$	0.04
Diluted net income (loss) per share	$	0.04	$	(0.02	)	$	0.02	$	0.04


(1)	Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi Field.


(2)	Reflects a $1.3 million restructuring charge and $0.8 million of non-recurring expenses primarily associated with the exercise of 4.0 million of 4.8 million of previously outstanding stock options and warrants.


(3)	Includes $608,000 of non-recurring expenses related to the retirement of an officer of the Company.

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Jun. 30, 2015
Accounting Policies [Abstract]
Principles of Consolidation and Reporting	Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported income or stockholders' equity.
Use of Estimates	Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("GAAP") requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts	Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method.
Oil and Natural Gas Properties	Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized.
Limitation on Capitalized Costs	Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent, and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties.
Other Property and Equipment	Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furniture and equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred.
Deferred Financing Costs	Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Asset Retirement Obligations	Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.
Fair Value of Financial Instruments	Fair Value of Financial Instruments.Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors.
Stock-based Compensation	Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense. Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricing model to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fair value is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that the recipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service.
Revenue Recognition	Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment. Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations may generate revenues under several forms of operational or contractual arrangements. We have utilized the technology on wells that we develop and operate and on certain wells that we operate under farm-outs from other operators. In these cases, our revenues take the form of net sales of oil and gas production. We have also provided the technology to third parties under contractual arrangements that generate fees for the technology which are based on the net profits from oil and gas production. Under these contracts, we may be required to bear part or all of the incremental installation and capital costs for the technology. In other cases, we may be compensated for our technology through a fixed or variable fee per well, which does not require us to bear any net costs of installation or other capital costs. In the future, we may enter into licensing contracts which allow for the sale and installation of the technology by third parties to their customers or we may license the technology to larger organizations for use in specified geographic areas or on other broad terms. In all cases, we evaluate the substance of the contractual arrangement and recognize 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. In early June 2015, the Company initiated derivative transactions using costless collars to reduce its exposure to oil price volatility for a substantial portion of its forecasted production for the months of July 2015 through December 2015. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to a ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as a result of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes.
Depreciation, Depletion and Amortization	Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computer equipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment.
Intangible Assets - Intellectual Property	Intangible Assets - Intellectual Property. The Company capitalizes the external costs, consisting primarily of legal costs, related to securing its patents and trademarks. The costs related to patents are amortized over the remaining patent life which is less than the expected useful life of each patent. Trademarks are perpetual and are not amortized.
Income Taxes	Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense.
Earnings (loss) per share	Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common shares outstanding less any non-vested restricted common stock outstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants, and non-vested restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method. Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shall be assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPS computation. Potential dilutive common shares are excluded from the computation if their effect is anti-dilutive.
Recent Accounting Pronouncements	Recent Accounting Pronouncements. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers: (Topic 606) to provide guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provides for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements. In April 2015, the FASB issued ASU 2015-03 (ASC Subtopic 835-30), Interest-Imputation of Interest: Simplifying the Presentation of Debt Issuance Costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The amendments in this ASU are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The adoption of this new guidance will not have a material impact on the Company's consolidated financial statements and disclosures.

Receivables (Tables)

12 Months Ended

Jun. 30, 2015

Receivables [Abstract]

Schedule of receivables

As of June 30, 2015 and June 30, 2014 our receivables consisted of the following:



	June 30, 2015		June 30, 2014
Receivables from oil and gas sales	$	3,122,155	$	1,456,146
Other	318		1,066
Total receivables	$	3,122,473	$	1,457,212

Prepaid Expenses and Other Current Assets (Tables)

12 Months Ended

Jun. 30, 2015

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

Schedule of prepaid expenses and other current assets

As of June 30, 2015 and June 30, 2014 our prepaid expenses and other current assets consisted of the following:



	June 30, 2015		June 30, 2014
Prepaid insurance	$	178,994	$	169,288
Prepaid federal and state income taxes	22,542		419,999
Equipment inventory	81,538		85,888
Retainers and deposits	26,978		29,478
Other prepaid expenses	59,352		42,800
Prepaid expenses and other current assets	$	369,404	$	747,453

Property and Equipment (Tables)

12 Months Ended

Jun. 30, 2015

Property, Plant and Equipment [Abstract]

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

As of June 30, 2015 and June 30, 2014, our oil and natural gas properties and other property and equipment consisted of the following:



	June 30, 2015			June 30, 2014
Oil and natural gas properties
Property costs subject to amortization	$	57,718,653		$	47,166,282
Less: Accumulated depreciation, depletion, and amortization	(12,531,767		)	(9,344,212		)
Unproved properties not subject to amortization	—			—
Oil and natural gas properties, net	45,186,886			37,822,070
Other property and equipment
Furniture, fixtures and office equipment, at cost	287,680			343,178
Artificial lift technology equipment, at cost	319,994			377,943
Less: Accumulated depreciation	(330,918		)	(296,294		)
Other property and equipment, net	$	276,756		$	424,827

Other Assets (Tables)

12 Months Ended

Jun. 30, 2015

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

Schedule of other assets

AAs of June 30, 2015 and June 30, 2014 our other assets consisted of the following:



	June 30, 2015			June 30, 2014
Patent costs	538,276			305,592
Less: Accumulated amortization of patent costs	(47,063		)	(27,050		)
Deferred loan costs	337,078			243,003
Less: Accumulated amortization of deferred loan costs	(147,057		)	(98,421		)
Trademarks	44,803			40,928
Other assets, net	$	726,037		$	464,052

Restructuring (Tables)

12 Months Ended

Jun. 30, 2015

Restructuring and Related Activities [Abstract]

Restructuring and Related Costs

Our disposition of the accrued restructuring charges is as follows:



Type of Cost	Balance at December 31, 2013		Payments			Adjustment to Cost			Balance at June 30, 2015
Salary continuation liability	$	615,721	$	(615,721	)	$	—		$	—
Incentive compensation costs	185,525		(185,525		)	—			—
Other benefit costs and employer taxes	154,575		(110,144		)	(44,431		)	—
Accrued restructuring charges	$	955,821	$	(911,390	)	$	(44,431	)	$	—

Accrued Liabilities and Other (Tables)

12 Months Ended

Jun. 30, 2015

Other Liabilities Disclosure [Abstract]

Other Current Liabilities

As of June 30, 2015 and June 30, 2014 our other current liabilities consisted of the following:



	June 30, 2015		June 30, 2014
Accrued incentive and other compensation	$	578,910	$	1,358,653
Accrued restructuring charges	—		530,412
Officer retirement costs	—		288,258
Asset retirement obligations due within one year	57,223		146,703
Accrued royalties, including suspended accounts	75,164		89,179
Accrued franchise taxes	94,885		87,575
Accrued - other	49,191		57,224
Accrued liabilities and other	$	855,373	$	2,558,004

Asset Retirement Obligations (Tables)

12 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Schedule of reconciliation of the beginning and ending asset retirement obligation

The following is a reconciliation of the beginning and ending asset retirement obligation for the years ended June 30, 2015 and 2014:



	Years Ended
	2015			2014
Asset retirement obligations—beginning of period	$	352,215		$	615,551
Liabilities incurred (1)	564,019			—
Liabilities settled	(137,604		)	(323,665		)
Liabilities sold	(52,526		)	(48,273		)
Accretion of discount	34,866			41,626
Revisions to previous estimates	12,020			66,976
Less: current asset retirement obligations	(57,223		)	(146,703		)
Asset retirement obligations—end of period	$	715,767		$	205,512


(1)	Primarily attributable to the reversion of our working interest in the Delhi Field in November 2014.

Stock-Based Incentive Plan (Tables)

12 Months Ended

Jun. 30, 2015

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

Summary of information regarding outstanding Stock Options and Incentive Warrants and the changes during the fiscal year

The following summary presents information regarding outstanding Stock Options as of June 30, 2015, and the changes during the fiscal year:



	Number of Stock Options		Weighted Average Exercise Price		Aggregate Intrinsic Value(1)		Weighted Average Remaining Contractual Term (in years)
Stock Options outstanding at June 30, 2014	178,061		$	2.08
Granted	—		—
Exercised	(87,000	)	$	1.63
Canceled or forfeited	—		—
Expired	—		—
Stock Options outstanding at June 30, 2015	91,061		$	2.50	$	372,000	1.3
Vested or expected to vest at June 30, 2015	91,061		$	2.50	$	372,000	1.3
Exercisable at June 30, 2015	91,061		$	2.50	$	372,000	1.3


(1)	Based upon the difference between the market price of our common stock on the last trading date of the period ($6.59 as of June 30, 2015) and the Stock Option exercise price of in-the-money Stock Option.

Schedule of Restricted Stock transactions

The following table summarizes Contingent Restricted Stock activity:



	Number of Restricted Stock Units	Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2015 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at July 1, 2014	—	—
Performance-based awards granted	38,325	$	10.05	$	—
Market-based awards granted	17,961	4.26		—
Unvested at June 30, 2015	56,286	$	8.20	$	57,004	2.5

(1) Excludes $385,166 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

The following table sets forth the Restricted Stock transactions for the year ended June 30, 2015:



	Number of Restricted Shares		Weighted Average Grant-Date Fair Value		Unamortized Compensation Expense at June 30, 2015 (1)		Weighted Average Remaining Amortization Period (Years)
Unvested at June 30, 2014	140,067		$	8.70	$	—
Service-based awards granted	100,910		9.53
Performance-based awards granted	76,642		10.05
Market-based awards granted	35,914		7.59
Vested	(91,306	)	8.40
Forfeited	—		—
Unvested at June 30, 2015	262,227		$	9.37	$	1,306,990	2.3


(1)	Excludes $770,252 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Supplemental Disclosure of Cash Flow Information (Tables)

12 Months Ended

Jun. 30, 2015

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, 2015, 2014, and 2013 are as follows:



	June 30,
	2015		2014			2013
Income taxes paid	$	220,000	$	755,941		$	699,874
Income tax refunds	331,733		—			—
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	5,422,566		(183,766		)	(1,535,322		)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	576,039		66,976			65,575
Accrued purchases of treasury stock	170,283		—			—
Previously acquired Company shares swapped by holders to pay stock option exercise price	$	—	$	618,606		$	—

Income Taxes (Tables)

12 Months Ended

Jun. 30, 2015

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, 2015		June 30, 2014		June 30, 2013
Current:
Federal	$	1,413,296	$	386,018	$	857,480
State	608,436		161,168		659,303
Total current income tax provision	2,021,732		547,186		1,516,783
Deferred:
Federal	1,282,059		1,319,727		2,546,495
State	140,430		25,085		(33,517		)
Total deferred income tax provision	1,422,489		1,344,812		2,512,978
	$	3,444,221	$	1,891,998	$	4,029,761

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



	June 30, 2015			June 30, 2014			June 30, 2013
Income tax provision (benefit) computed at the statutory federal rate:	$	2,868,267		$	1,866,366		$	3,623,784
Reconciling items:
State income taxes, net of federal tax benefit	595,708			189,081			413,019
Permanent differences related to stock-based compensation	—			(155,817		)	8,933
Expiring NOLs related to 2004 reverse merger	—			—			600,964
Deferred tax asset valuation adjustment	—			—			(600,964		)
Other permanent differences	(19,754		)	(7,632		)	(15,975		)
Income tax provision	$	3,444,221		$	1,891,998		$	4,029,761

Schedule of components of deferred taxes

The components of our deferred taxes are detailed in the table below:



	June 30, 2015			June 30, 2014			June 30, 2013
Deferred tax assets:
Non-qualified stock-based compensation	$	173,647		$	134,469		$	774,673
Net operating loss carry-forwards	400,288			427,249			427,249
AMT credit carry-forward*	701,254			701,254			502,466
Other	91,113			165,775			28,170
Gross deferred tax assets	1,366,302			1,428,747			1,732,558
Valuation allowance	(292,446		)	(292,446		)	(292,446		)
Total deferred tax assets	1,073,856			1,136,301			1,440,112
Deferred tax liability:
Oil and natural gas properties	(12,233,993		)	(10,873,949		)	(9,832,948		)
Total deferred tax liability	(12,233,993		)	(10,873,949		)	(9,832,948		)
Net deferred tax liability	$	(11,160,137	)	$	(9,737,648	)	$	(8,392,836	)

_______________________________________________________________________________


*	Total AMT credit carry-forward is $901,545. Our net deferred tax liability does not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation.

Net Income Per Share (Tables)

12 Months Ended

Jun. 30, 2015

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,
	2015		2014		2013
Numerator
Net income attributable to common shareholders	$	4,317,555	$	2,923,011	$	5,954,126
Denominator
Weighted average number of common shares—Basic	32,817,456		30,895,832		28,205,467
Effect of dilutive securities:
Contingent restricted stock grants	4,422		—		—
Common stock warrants issued in connection with equity and financing transactions	—		—		878
Stock Options and Incentive Warrants	102,140		1,668,235		3,768,786
Total weighted average dilutive securities	106,562		1,668,235		3,769,664
Weighted average number of common shares and dilutive potential common shares used in diluted EPS	32,924,018		32,564,067		31,975,131
Net income per common share—Basic	$	0.13	$	0.09	$	0.21
Net income per common share—Diluted	$	0.13	$	0.09	$	0.19

Schedule of outstanding potentially dilutive securities

as of June 30, 2015:



Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2015
Contingent Restricted Stock grants	$	—	17,961
Stock Options	2.50		91,061
Total	$	2.09	109,022

The following are reflected in the calculation of diluted earnings per share as of June 30, 2014:

The following are reflected in the calculation of diluted earnings per share as of June 30, 2013:



Outstanding Potential Dilutive Securities	Weighted Average Exercise Price		Outstanding at June 30, 2013
Common stock warrants issued in connection with equity and financing transactions	$	2.50	1,165
Stock Options and Incentive Warrants	1.99		4,822,820
Total	$	1.99	4,823,985

Commitments and Contingencies (Tables)

12 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of future minimum lease commitments under the operating lease

Future minimum lease commitments as of June 30, 2015 under this operating lease are as follows:



For the fiscal year ended June 30,
2016	$	159,011
2017	13,251
Total	$	172,262

Concentrations of Credit Risk (Tables)

12 Months Ended

Jun. 30, 2015

Risks and Uncertainties [Abstract]

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



	Year Ended June 30,
Customer	2015		2014		2013
Plains Marketing L.P. (includes Delhi production)	99	%	96	%	90	%
Enterprise Crude Oil LLC	—	%	2	%	4	%
Flint Hills	—	%	1	%	2	%
ETC Texas Pipeline, LTD.	—	%	1	%	—	%
All others	1	%	—	%	4	%
Total	100	%	100	%	100	%

Derivatives (Tables)

12 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of crude oil derivative positions

The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2015.



Period	Type of Contract	Volumes (in Bbls./day)	Weighted Average Floor Price per Bbl.	Weighted Average Ceiling Price per Bbl.	Weighted Average Collar Spread per Bbl.
Months of July 2015 through December 2015	Costless Collar	1,100	$55.00	$64.05	$9.05

Schedule of assets and liabilities measured on a recurring basis

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value Measurement (Tables)

12 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2015. All items included in the tables below are Level 2 inputs within the fair value hierarchy:



	June 30, 2015
Asset (Liability)	Gross Amounts Recognized			Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts Presented in the Consolidated Balance Sheets
Current derivative assets	$	355,555		$	(355,555	)	$	—
Current derivative liabilities	(465,529		)	355,555			(109,974		)
Total	$	(109,974	)	$	—		$	(109,974	)

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

12 Months Ended

Jun. 30, 2015

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

Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $576,039, $66,976 and $65,575 during the years ended June 30, 2015, 2014, and 2013, respectively.



	For the Years Ended June 30,
	2015		2014		2013
Oil and natural gas activities
Property acquisition costs:
Proved property	$	—	$	—	$	26,449
Unproved property	—		47,344		195,599
Exploration costs	—		757,423		4,356,640
Development costs	10,975,637		18,566		79,035
Total costs incurred for oil and natural gas activities	$	10,975,637	$	823,333	$	4,657,723

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, 2012	11,638,618		492,473		7,860,156		13,441,116
Revisions of previous estimates (a)	1,826,053		975,515		27,679		2,806,181
Sales of minerals in place	(485,536	)	(480,832	)	(7,726,032	)	(2,254,038	)
Production (sales volumes)	(196,380	)	(7,271	)	(139,006	)	(226,819	)
June 30, 2013	12,782,755		979,885		22,797		13,766,440
Revisions of previous estimates (b)	(1,919,052	)	1,269,588		2,412,677		(247,350	)
Improved recovery, extensions and discoveries	17,146		32,731		498,044		132,884
Sales of minerals in place	(184,722	)	—		—		(184,722	)
Production (sales volumes)	(169,783	)	(3,516	)	(26,655	)	(177,742	)
June 30, 2014	10,526,344		2,278,688		2,906,863		13,289,510
Revisions of previous estimates (c)	(64,074	)	156,195		(2,894,703	)	(390,330	)
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(450,294	)	(1,288	)	(7,221	)	(452,786	)
June 30, 2015	10,011,976		2,433,595		4,939		12,446,394
Proved developed reserves:
June 30, 2012	7,670,934		111,978		1,499,382		8,032,809
June 30, 2013	10,077,522		8,539		22,797		10,089,861
June 30, 2014	7,858,224		32,164		481,042		7,970,562
June 30, 2015	7,347,231		1,572		4,939		7,349,626
Proved undeveloped reserves:
June 30, 2012	3,967,684		380,495		6,360,774		5,408,307
June 30, 2013	2,705,233		971,346		—		3,676,579
June 30, 2014	2,668,120		2,246,524		2,425,821		5,318,948
June 30, 2015	2,664,745		2,432,023		—		5,096,768

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, 2015, 2014, and 2013 are as follows:



	For the Years Ended June 30,
	2015			2014			2013
Future cash inflows	$	807,030,282		$	1,193,515,075		$	1,436,980,607
Future production costs and severance taxes	(309,225,333		)	(475,387,931		)	(510,902,614		)
Future development costs	(49,691,006		)	(46,154,178		)	(60,742,406		)
Future income tax expenses	(123,888,665		)	(195,581,510		)	(275,113,560		)
Future net cash flows	324,225,278			476,391,456			590,222,027
10% annual discount for estimated timing of cash flows	(165,028,739		)	(250,313,784		)	(283,001,328		)
Standardized measure of discounted future net cash flows	$	159,196,539		$	226,077,672		$	307,220,699

Schedule of NYMEX prices used in determining future cash flows



	Year Ended June 30,
	2015				2014				2013
	Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	71.88	$	3.44	$	100.37	$	4.10	$	91.51	$	3.44

Schedule of changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves

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



	For the Years Ended June 30,
	2015			2014			2013
Balance, beginning of year	$	226,077,672		$	307,220,699		$	283,597,493
Net changes in sales prices and production costs related to future production	(88,043,095		)	(73,439,526		)	(35,184,725		)
Changes in estimated future development costs	(9,585,405		)	9,848,614			(566,125		)
Sales of oil and gas produced during the period, net of production costs	(18,538,016		)	(16,479,934		)	(19,569,182		)
Net change due to extensions, discoveries, and improved recovery	—			775,574			—
Net change due to revisions in quantity estimates	(9,391,321		)	(23,757,788		)	64,817,544
Net change due to sales of minerals in place	—			(3,150,277		)	(34,119,027		)
Development costs incurred during the period	7,785,095			—			747,656
Accretion of discount	31,974,540			45,896,187			41,678,733
Net change in discounted income taxes	34,157,767			58,073,450			10,175,957
Net changes in timing of production and other (a)	(15,240,698		)	(78,909,327		)	(4,357,625		)
Balance, end of year	$	159,196,539		$	226,077,672		$	307,220,699

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, 2015

Summary of quarterly financial information

The following table presents summarized quarterly financial information for the years ended June 30, 2015 and 2014:



2015	First		Second (1)		Third		Fourth
Revenues	$	4,004,827	$	7,708,067	$	7,064,689	$	9,063,682
Operating income	1,840,866		2,162,294		1,245,990		3,334,547
Net income available to common shareholders	$	960,435	$	1,071,342	$	566,011	$	1,719,767
Basic net income per share	$	0.03	$	0.03	$	0.02	$	0.05
Diluted net income per share	$	0.03	$	0.03	$	0.02	$	0.05



2014	First		Second (2)			Third (3)		Fourth
Revenues	$	4,633,699	$	4,392,289		$	4,337,006	$	4,310,514
Operating income (loss)	1,963,897		(158,095		)	1,357,534		2,364,811
Net income (loss) available to common shareholders	$	1,303,876	$	(577,459	)	$	755,125	$	1,441,469
Basic net income (loss) per share	$	0.05	$	(0.02	)	$	0.02	$	0.04
Diluted net income (loss) per share	$	0.04	$	(0.02	)	$	0.02	$	0.04


(1)	Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi Field.


(2)	Reflects a $1.3 million restructuring charge and $0.8 million of non-recurring expenses primarily associated with the exercise of 4.0 million of 4.8 million of previously outstanding stock options and warrants.


(3)	Includes $608,000 of non-recurring expenses related to the retirement of an officer of the Company.

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Accounting Policies [Abstract]
Allowance for doubtful accounts	$ 0	$ 0
Oil and natural gas properties
Limitation on Capitalized Costs
Discount rate for present value (as a percent)	10.00%
Period considered for computing unweighted arithmetic average of oil and natural gas prices	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

Receivables (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Receivables [Abstract]
Receivables from oil and gas sales	$ 3,122,155	$ 1,456,146
Other	318	1,066
Total receivables	$ 3,122,473	$ 1,457,212

Prepaid Expenses and Other Current Assets (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Prepaid insurance	$ 178,994	$ 169,288
Prepaid federal and state income taxes	22,542	419,999
Equipment inventory	81,538	85,888
Retainers and deposits	26,978	29,478
Other prepaid expenses	59,352	42,800
Prepaid expenses and other current assets	$ 369,404	$ 747,453

Property and Equipment - Summary of Property and Equipment (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Oil and natural gas properties
Property costs subject to amortization	$ 57,718,653	$ 47,166,282
Less: Accumulated depreciation, depletion, and amortization	(12,531,767)	(9,344,212)
Unproved properties not subject to amortization	0	0
Oil and natural gas properties, net	45,186,886	37,822,070
Other property and equipment
Furniture, fixtures and office equipment, at cost	287,680	343,178
Artificial lift technology equipment, at cost	319,994	377,943
Less: Accumulated depreciation	(330,918)	(296,294)
Other property and equipment, net	$ 276,756	$ 424,827

Property and Equipment - Narrative (Details)			12 Months Ended
Property and Equipment - Narrative (Details)	Oct. 24, 2014 USD ($)	Dec. 01, 2013 USD ($)	Jun. 30, 2015 USD ($) well	Jun. 30, 2014 USD ($) well	Jun. 30, 2013 USD ($)
Property, Plant and Equipment [Line Items]
Installation costs of artificial lift technology			$ 217,733	$ 377,943
Wells installed with artificial lift technology, for third party customer (total wells in program) \| well			2	5
Wells installed with artificial lift technology, for third party customer \| well			5	3
Percentage of net profits from production				25.00%
Additional depreciation			$ 275,682
Number of wells removed and installed with artificial lift technology \| well			3
Proceeds from asset sales			$ 398,242	$ 542,347	$ 3,479,976
Oil and natural gas properties
Property, Plant and Equipment [Line Items]
Proceeds from asset sales	$ 389,165	$ 402,500

Other Assets (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Patent costs	$ 538,276	$ 305,592
Less: Accumulated amortization of patent costs	(47,063)	(27,050)
Deferred loan costs	337,078	243,003
Less: Accumulated amortization of deferred loan costs	(147,057)	(98,421)
Trademarks	44,803	40,928
Other assets, net	$ 726,037	$ 464,052

Restructuring - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
Restructuring - Narrative (Details) - USD ($)	Dec. 31, 2013	Dec. 31, 2014	Jun. 30, 2015	Nov. 02, 2013
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve				$ 1,332,186
Non-cash stock-based compensation expense	$ 800,000
Accrued restructuring charges
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	$ 955,821	$ 955,821	$ 0
Restructuring Charges \| Stock Compensation, Restructuring
Restructuring Cost and Reserve [Line Items]
Non-cash stock-based compensation expense		$ 376,365

Restructuring - Schedule of Restructuring and Related Costs (Details)	18 Months Ended
	Jun. 30, 2015 USD ($)
Salary continuation liability
Restructuring Reserve [Roll Forward]
Beginning balance	$ 615,721
Payments	(615,721)
Adjustment to Cost	0
Ending balance	0
Incentive compensation costs
Restructuring Reserve [Roll Forward]
Beginning balance	185,525
Payments	(185,525)
Adjustment to Cost	0
Ending balance	0
Other benefit costs and employer taxes
Restructuring Reserve [Roll Forward]
Beginning balance	154,575
Payments	(110,144)
Adjustment to Cost	(44,431)
Ending balance	0
Accrued restructuring charges
Restructuring Reserve [Roll Forward]
Beginning balance	955,821
Payments	(911,390)
Adjustment to Cost	(44,431)
Ending balance	$ 0

Accrued Liabilities and Other - Schedule of Other Current Liabilities (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014
Other Liabilities Disclosure [Abstract]
Accrued incentive and other compensation	$ 578,910	$ 1,358,653
Accrued restructuring charges	0	530,412
Officer retirement costs	0	288,258
Asset retirement obligations due within one year	57,223	146,703
Accrued royalties, including suspended accounts	75,164	89,179
Accrued franchise taxes	94,885	87,575
Accrued - other	49,191	57,224
Accrued liabilities and other	$ 855,373	$ 2,558,004

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

12 Months Ended

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2013

Reconciliation of the beginning and ending asset retirement obligation

Asset retirement obligations—beginning of period

$ 352,215

$ 615,551

Liabilities incurred (1)

^[1]

564,019

Liabilities settled

(137,604)

(323,665)

Liabilities sold

(52,526)

(48,273)

Accretion of discount

34,866

41,626

$ 72,312

Revisions to previous estimates

12,020

66,976

Less: current asset retirement obligations

(57,223)

(146,703)

Asset retirement obligations - end of period

$ 715,767

$ 205,512

[1]	Primarily attributable to the reversion of our working interest in the Delhi Field in November 2014.

Stockholders' Equity - Narrative (Details) - USD ($)	1 Months Ended	3 Months Ended			12 Months Ended
Stockholders' Equity - Narrative (Details) - USD ($)	Dec. 31, 2013	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2013	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2012	May 12, 2015
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Common shares issued during period for share based compensation (shares)						1,568,832
Proceeds from the exercise of stock options					$ 141,600	$ 3,252,801	$ 70,719
Stock issued, nonqualified stock options and incentive warrants noncash (shares)						2,635,696
Shares received in lieu of cash payment (shares)						50,956
Shares received in lieu of cash payment, average cost of shares (in USD per share)						$ 12.14
Dividends paid					9,833,642	$ 9,723,833
Cash dividends paid (per common share)	$ 0.10	$ 0.05	$ 0.10	$ 0.10
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Payments of Ordinary Dividends, Preferred Stock and Preference Stock					674,302	$ 674,302	674,302
Treasury Stock, Number of Shares and Restriction Disclosures [Abstract]
Treasury stock retired (shares)						801,889
Treasury stock retired, value						$ 1,019,840
Purchases of treasury stock (shares)						186,714
Purchases of treasury stock					$ 504,124	$ 2,273,857
Treasury stock acquired, average cost (in USD per share)						$ 12.18
Series A Cumulative Preferred Stock
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Issuance of preferred stock (in shares)								317,319
Proceeds from issuance of preferred stock, net								$ 6,930,535
Cumulative Preferred Stock (as a percent)					8.50%	8.50%		8.50%
Preferred stock, liquidation preference (in dollars per share)					$ 25.00	$ 25.00		$ 25.00
Preferred Stock, Dividend Rate, Per-Dollar-Amount					$ 0.177083
Payments of Ordinary Dividends, Preferred Stock and Preference Stock					$ 674,302	$ 674,302	$ 674,302
Weighted Average \| Series A Cumulative Preferred Stock
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Share Price								$ 23.80
Public Offering \| Series A Cumulative Preferred Stock
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Issuance of preferred stock (in shares)								220,000
At the Market Offering \| Series A Cumulative Preferred Stock
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Issuance of preferred stock (in shares)								97,319
Common Stock
Treasury Stock, Number of Shares and Restriction Disclosures [Abstract]
Purchases of treasury stock (shares)					70,907	186,714
Stock acquired for payroll tax liabilities from vestings of stock based compensation plan (in shares)					7,535
Stock acquired for payroll tax liabilities from vestings of stock based compensation plan (in USD per share)					$ 9.16
2015 Share Repurchase Program \| Common Stock
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]
Amount authorized to be repurchased									$ 5,000,000
Treasury Stock, Number of Shares and Restriction Disclosures [Abstract]
Purchases of treasury stock (shares)					63,372
Treasury stock acquired, average cost (in USD per share)					$ 6.87

Stock-Based Incentive Plan - Narrative (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise of stock options (shares)		87,000		550,000
Options, Exercised, Intrinsic Value		$ 501,810		$ 5,233,480
Non-cash stock-based compensation expense	$ 800,000
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options and Incentive Warrants, Grants (in shares)		0	0	0
Stock Options and Incentive Warrants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exercise of stock options (shares)			4,644,759
Options, Exercised, Intrinsic Value			$ 47,504,114
Options and Incentive Warrants Vested in Period		0	0	18,922
Options and Incentive Warrants, vested in period, grant date, fair value		$ 0	$ 0	$ 46,359
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock, vested (shares)		91,306	277,198	277,198
Restricted stock, vested in period, grant date fair value		$ 766,970	$ 1,796,243	$ 1,427,570
Non-cash stock-based compensation expense		962,813	$ 1,728,687	$ 1,531,745
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash dividends paid		$ 19,160
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for granting (shares)		6,500,000
Shares available for grant (shares)		542,529
Minimum \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at grant date, per share		$ 4.26
Vesting period		3 years 3 months 18 days
Maximum \| Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at grant date, per share		$ 8.40
Vesting period		2 years 6 months 18 days

Stock-Based Incentive Plan - Schedule of Options and Incentive Warrants (Details) - USD ($)

12 Months Ended

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2013

Number of Stock Options

Stock Options Outstanding, Beginning of Period (in shares)

178,061

Stock Options, Grants (in shares)

Stock Options , Exercises (in shares)

(87,000)

(550,000)

Stock Options, Forfeited or Canceled (in shares)

Stock Options, Expirations (in shares)

Stock Options Outstanding, End of Period (in shares)

91,061

178,061

Stock Options, Vested and Expected to Vest (in shares)

91,061

Stock Options, Exercisable (in shares)

91,061

Weighted Average Exercise Price

Stock Options Outstanding, Weighted Average Exercise Price, Beginning of Period (in USD per share)

$ 2.08

Stock Options, Grants, Weighted Average Exercise Price (in USD per share)

0.00

Stock Options, Exercises, Weighted Average Exercise Price (in USD per share)

1.63

Stock Options, Forfeitures, Weighted Average Exercise Price (in USD per share)

0.00

Stock Options, Expirations, Weighted Average Exercise Price (in USD per share)

0.00

Stock Options, Weighted Average Exercise Price, End of Period (in USD per share)

2.50

$ 2.08

Stock Options, Vested and Expected to Vest, Weighted Average Exercise Price (in USD per share)

2.50

Stock Options, Exercisable, Weighted Average Exercise Price (in USD per share)

$ 2.50

Aggregate Intrinsic Value

Stock Options, Outstanding, Aggregate Intrinsic Value

^[1]

$ 372,000

Stock Options, Vested and Expected to Vest, Aggregate Intrinsic Value

^[1]

372,000

Stock Options, Exercisable, Aggregate Intrinsic Value

^[1]

$ 372,000

Stock Options, Outstanding, Weighted Average Remaining Contractual Term (in years)

1 year 3 months 18 days

Stock Options, Vested and Expected to Vest, Weighted Average Remaining Contractual Term (in years)

1 year 3 months 18 days

Stock Options, Exercisable, Weighted Average Remaining Contractual Term (in years)

1 year 3 months 18 days

Stock Options and Incentive Warrants

Number of Stock Options

Stock Options , Exercises (in shares)

(4,644,759)

Common Stock | Stock Options and Incentive Warrants

Aggregate Intrinsic Value

Share Price

$ 6.59

[1]	Based upon the difference between the market price of our common stock on the last trading date of the period ($6.59 as of June 30, 2015) and the Stock Option exercise price of in-the-money Stock Option.

Stock-Based Incentive Plan - Schedule of Restricted Stock (Details) - USD ($)

12 Months Ended

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2013

Restricted Stock

Nonvested, beginning of period (shares)

140,067

Vested (shares)

(91,306)

(277,198)

Forfeited (shares)

Nonvested, end of period (shares)

262,227

140,067

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

$ 8.70

Vested, weighted average grant date fair value (in USD per share)

8.40

Forfeited, weighted average grant date fair value (in USD per share)

0.00

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

$ 9.37

$ 8.70

Unamortized compensation expense

^[1]

$ 1,306,990

Weighted Average Remaining Amortization Period (in years)

2 years 3 months 18 days

Restricted Stock, Service Based

Grants (shares)

100,910

Grants, weighted average grant date fair value (in USD per share)

$ 9.53

Restricted Stock, Performance Based

Grants (shares)

76,642

Grants, weighted average grant date fair value (in USD per share)

$ 10.05

Potential future compensation expense

$ 770,252

Restricted Stock, Market Based

Grants (shares)

35,914

Grants, weighted average grant date fair value (in USD per share)

$ 7.59

[1]	Excludes $770,252 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Stock-Based Incentive Plan - Schedule of Contingent Restricted Stock (Details)

12 Months Ended

Jun. 30, 2015

USD ($)

$ / shares

Contingent Restricted Stock Grants

Number of Restricted Stock Units

Nonvested, beginning of period (shares) | shares

Nonvested, end of period (shares) | shares

56,286

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

$ 0.00

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

$ 8.20

Unamortized compensation expense | $

$ 57,004

^[1]

Weighted Average Remaining Amortization Period (in years)

2 years 6 months

Contingent Restricted Stock, Performance Based

Number of Restricted Stock Units

Grants (shares) | shares

38,325

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

$ 10.05

Potential future compensation expense | $

$ 385,166

Contingent Restricted Stock, Market Based

Number of Restricted Stock Units

Grants (shares) | shares

17,961

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

$ 4.26

[1]	Excludes $385,166 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes.

Supplemental Disclosure of Cash Flow Information - Schedule of Supplement Cash Flow (Details) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Supplemental Cash Flow Elements [Abstract]
Income taxes paid	$ 220,000	$ 755,941	$ 699,874
Income tax refunds	331,733	0	0
Non-cash transactions:
Change in accounts payable used to acquire property and equipment	5,422,566	(183,766)	(1,535,322)
Oil and natural gas property costs attributable to the recognition of asset retirement obligations	576,039	66,976	65,575
Accrued purchases of treasury stock	170,283	0	0
Previously acquired Company shares swapped by holders to pay stock option exercise price	$ 0	$ 618,606	$ 0

Income Taxes - Narrative (Details) - USD ($)	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Operating Loss Carryforwards [Line Items]
Unrecognized tax benefits	$ 0	$ 0	$ 0
Statutory tax rate	34.00%
Tax loss carryforwards from exercise of options and warrants		$ 24,600,000
Approximate amount of carryforward depletion	$ 11,600,000
Maximum
Operating Loss Carryforwards [Line Items]
Percentage of carryforward depletion	65.00%
Federal
Operating Loss Carryforwards [Line Items]
Tax loss carryforwards	$ 25,800,000
Tax loss carryforward from reverse merger	1,200,000
Carryforward from reverse merger	300,000
Annual amount of carryforward from reverse merger through 2023	39,648
State
Operating Loss Carryforwards [Line Items]
Tax loss carryforwards	24,200,000
Tax loss carryback	19,000,000
Louisiana \| State
Operating Loss Carryforwards [Line Items]
Tax loss carryforwards	1,500,000
Tax Year 2015 \| State
Operating Loss Carryforwards [Line Items]
Tax loss carryforwards	3,800,000
Settlement with Taxing Authority \| Louisiana \| State
Operating Loss Carryforwards [Line Items]
Amount of tax refund requested	$ 1,500,000

Income Taxes - Components of Income Tax Provision (Benefit) (Details) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Current:
Federal	$ 1,413,296	$ 386,018	$ 857,480
State	608,436	161,168	659,303
Total current income tax provision	2,021,732	547,186	1,516,783
Deferred:
Federal	1,282,059	1,319,727	2,546,495
State	140,430	25,085	(33,517)
Total deferred income tax provision	1,422,489	1,344,812	2,512,978
Total income tax provision	$ 3,444,221	$ 1,891,998	$ 4,029,761

Income Taxes - Reconciliation of Statutory and Income Tax Expense (Details) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Income Tax Disclosure [Abstract]
Income tax provision (benefit) computed at the statutory federal rate:	$ 2,868,267	$ 1,866,366	$ 3,623,784
State income taxes, net of federal tax benefit	595,708	189,081	413,019
Permanent differences related to stock-based compensation	0	(155,817)	8,933
Expiring NOLs related to 2004 reverse merger	0	0	600,964
Deferred tax asset valuation adjustment	0	0	(600,964)
Other permanent differences	(19,754)	(7,632)	(15,975)
Total income tax provision	$ 3,444,221	$ 1,891,998	$ 4,029,761

Income Taxes - Schedule of Deferred Income Taxes (Details) - USD ($)

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2013

Deferred tax assets:

Non-qualified stock-based compensation

$ 173,647

$ 134,469

$ 774,673

Net operating loss carry-forwards

400,288

427,249

AMT credit carry-forward

^[1]

701,254

502,466

Other

91,113

165,775

28,170

Gross deferred tax assets

1,366,302

1,428,747

1,732,558

Valuation allowance

(292,446)

Total deferred tax assets

1,073,856

1,136,301

1,440,112

Deferred tax liability:

Oil and natural gas properties

(12,233,993)

(10,873,949)

(9,832,948)

Total deferred tax liability

(12,233,993)

(10,873,949)

(9,832,948)

Net deferred tax liability

(11,160,137)

$ (9,737,648)

$ (8,392,836)

AMT credit carry-forward

901,545

AMT associated with stock-based compensation

$ 200,291

[1]	Total AMT credit carry-forward is $901,545. Our net deferred tax liability does not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation.

Related Party Transactions - Narrative (Details) - USD ($)	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Vice President
Related Party Transaction [Line Items]
Related party payments	$ 26,579	$ 10,113	$ 10,113

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

3 Months Ended

12 Months Ended

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

^[1]

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

^[2]

Dec. 31, 2013

^[3]

Sep. 30, 2013

Jun. 30, 2015

Jun. 30, 2014

Jun. 30, 2013

Numerator

Net income attributable to common shareholders

$ 1,719,767

$ 566,011

$ 1,071,342

$ 960,435

$ 1,441,469

$ 755,125

$ (577,459)

$ 1,303,876

$ 4,317,555

$ 2,923,011

$ 5,954,126

Denominator

Weighted average number of common shares—Basic

32,817,456

30,895,832

28,205,467

Total weighted average dilutive securities

106,562

1,668,235

3,769,664

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

32,924,018

32,564,067

31,975,131

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

$ 0.05

$ 0.02

$ 0.03

$ 0.04

$ 0.02

$ (0.02)

$ 0.05

$ 0.13

$ 0.09

$ 0.21

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

$ 0.05

$ 0.02

$ 0.03

$ 0.04

$ 0.02

$ (0.02)

$ 0.04

$ 0.13

$ 0.09

$ 0.19

Contingent restricted stock grants

Weighted average dilutive securities

4,422

Common stock warrants issued in connection with equity and financing transactions

Weighted average dilutive securities

878

Stock Options and Incentive Warrants

Weighted average dilutive securities

102,140

1,668,235

3,768,786

[1]	Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi Field.
[2]	Includes $608,000 of non-recurring expenses related to the retirement of an officer of the Company.
[3]	Reflects a $1.3 million restructuring charge and $0.8 million of non-recurring expenses primarily associated with the exercise of 4.0 million of 4.8 million of previously outstanding stock options and warrants.

Net Income Per Share - Schedule of Outstanding Potentially Dilutive Securities (Details) - $ / shares	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Earnings Per Share [Abstract]
Contingent Restricted Stock grants, Weighted Average Exercise Price (in dollars per share)	$ 0.00
Stock Options, Weighted Average Exercise Price (in dollars per share)	2.50	$ 2.08
Common stock warrants issued in connection with equity and financing transactions, Weighted Average Exercise Price (in dollars per share)			$ 2.50
Stock Options and Incentive Warrants, Weighted Average Exercise Price (in dollars per share)			1.99
Total, Weighted Average Exercise Price (in dollars per share)	$ 2.09		$ 1.99
Contingent Restricted Stock grants	17,961
Stock Options	91,061	178,061
Common stock warrants issued in connection with equity and financing transactions			1,165
Stock Options and Incentive Warrants			4,822,820
Total	109,022		4,823,985

Unsecured Revolving Credit Agreement (Details) - Texas Capital Bank, N.A.	1 Months Ended	12 Months Ended
	Feb. 29, 2012 USD ($)	Jun. 30, 2015 USD ($) loan	Jun. 30, 2014 USD ($)
Revolving Credit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 50,000,000
Current borrowing base	5,000,000	$ 5,000,000
Term of debt instrument		4 years
Percentage of oil and gas properties as borrowing limitation		25.00%
Unused commitment fee percentage		0.50%
Loan costs incurred upon closing	50,000
Outstanding borrowings		$ 0	$ 0
Debt issuance costs	179,468
Unamortized debt issuance costs		32,411
Revolving Credit Facility \| Other Assets
Debt Instrument [Line Items]
Debt issuance costs		$ 157,610
Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 1,000,000
Commitment fee percentage		3.50%
Outstanding borrowings		$ 0	$ 0
LIBOR \| Revolving Credit Facility
Debt Instrument [Line Items]
Description of variable rate basis		Adjusted LIBOR
Interest Period One Term		1 month
Interest Period Two Term		2 months
Interest Period Three Term		3 months
Interest Period Four Term		6 months
Interest Period Payment Term		3 months
Prime Rate \| Revolving Credit Facility
Debt Instrument [Line Items]
Description of variable rate basis		Lender's prime rate
Federal Funds Rate \| Revolving Credit Facility
Debt Instrument [Line Items]
Description of variable rate basis		Federal Fund Rate
Basis spread on variable rate		0.50%
Maximum \| Revolving Credit Facility
Debt Instrument [Line Items]
Current ratio		1.5
Consolidated leverage ratio		2.5
Interest coverage ratio		3
Maximum \| Letter of Credit
Debt Instrument [Line Items]
Term of debt instrument		1 year
Maximum \| LIBOR \| Revolving Credit Facility
Debt Instrument [Line Items]
Number of loans outstanding \| loan		3

Commitments and Contingencies - Schedule of Future Minimum Lease Commitments (Details)	Jun. 30, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2016	$ 159,011
2017	13,251
Total	$ 172,262

Commitments and Contingencies - Narrative (Details)	12 Months Ended
Commitments and Contingencies - Narrative (Details)	Jun. 30, 2015 USD ($) senior_executive	Jun. 30, 2014 USD ($)	Jun. 30, 2013 USD ($)	Feb. 26, 2015 USD ($)	Jan. 26, 2015
Loss Contingencies [Line Items]
Overriding royalty interest in the Delhi Unit	4.8119%
Rent expense	$ 175,103	$ 174,229	$ 147,233
Employment Contracts
Loss Contingencies [Line Items]
Number of senior executives under agreement \| senior_executive	2
Total contingent obligations	$ 473,000
Minimum \| Employment Contracts
Loss Contingencies [Line Items]
Period of benefits to employee after termination	6 months
Maximum \| Employment Contracts
Loss Contingencies [Line Items]
Period of benefits to employee after termination	1 year
Denbury Resources, Inc
Loss Contingencies [Line Items]
Suspended overriding royalty revenue interest					2.89155%
Suspended overriding royalty interest, amount previously suspended				$ 712,000

Concentrations of Credit Risk - Schedule of Credit Risk (Details) - Net revenue - Major Customers	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Concentrations of Credit Risk
Percent of Total Revenue	100.00%	100.00%	100.00%
Plains Marketing L.P. (includes Delhi production)
Concentrations of Credit Risk
Percent of Total Revenue	99.00%	96.00%	90.00%
Enterprise Crude Oil LLC
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	2.00%	4.00%
Flint Hills
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	1.00%	2.00%
ETC Texas Pipeline, LTD.
Concentrations of Credit Risk
Percent of Total Revenue	0.00%	1.00%	0.00%
All others
Concentrations of Credit Risk
Percent of Total Revenue	1.00%	0.00%	4.00%

Retirement Plan (Details) - USD ($)	12 Months Ended
Retirement Plan (Details) - USD ($)	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2013
Compensation and Retirement Disclosure [Abstract]
Employer match of employee contributions of first 6% of eligible compensation (as a percent)	100.00%
Percentage of eligible compensation, matched 100% by employer	6.00%
Matching contribution to the plan	$ 85,676	$ 116,873	$ 89,810

Derivatives (Details)	1 Months Ended		12 Months Ended
Derivatives (Details)	Aug. 31, 2015 USD ($)	Jul. 31, 2015 USD ($)	Jun. 30, 2015 USD ($) $ / bbl bbl	Jun. 30, 2014 USD ($)	Jun. 30, 2013 USD ($)
Derivative [Line Items]
Net liability			$ 109,974
Gain (loss) on derivatives, net			$ (109,974)	$ 0	$ 0
Crude Oil \| Options
Derivative [Line Items]
Volumes (in Bbls./day) \| bbl			1,100
Weighted Average Floor Price per Bbl. \| $ / bbl			55.00
Weighted Average Ceiling Price per Bbl. \| $ / bbl			64.05
Weighted Average Put Spread per Bbl. \| $ / bbl			9.05
Crude Oil \| Options \| Subsequent Event
Derivative [Line Items]
Gain on derivatives	$ 412,985	$ 138,787
Cargill, Incorporated \| Line of Credit
Derivative [Line Items]
Credit line			$ 5,000,000

Fair Value Measurement - Assets and Liabilities Measured on Recurring Basis (Details) - Level 2	Jun. 30, 2015 USD ($)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Current derivative assets, Gross Amounts Recognized	$ 355,555
Current derivative assets, Gross Amounts Offset in the Consolidated Balance Sheet	(355,555)
Current derivative assets, Net Amounts Presented in the Consolidated Balance Sheets	0
Current derivative liabilities, Gross Amounts Recognized	(465,529)
Current derivative liabilities, Gross Amounts Offset in the Consolidated Balance Sheet	355,555
Current derivative liabilities, Net Amounts Presented in the Consolidated Balance Sheets	(109,974)
Total, Gross Amounts Recognized	(109,974)
Total, Gross Amounts Offset in the Consolidated Balance Sheet	0
Total, Net Amounts Presented in the Consolidated Balance Sheets	$ (109,974)

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, 2015	Jun. 30, 2014	Jun. 30, 2013
Property acquisition costs:
Proved property	$ 0	$ 0	$ 26,449
Unproved property	0	47,344	195,599
Exploration costs	0	757,423	4,356,640
Development costs	10,975,637	18,566	79,035
Total costs incurred for oil and natural gas activities	$ 10,975,637	$ 823,333	$ 4,657,723

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, 2015

Boe

Mcf

bbl

Jun. 30, 2014

Boe

Mcf

bbl

Jun. 30, 2013

Boe

Mcf

bbl

Jun. 30, 2012

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

13,289,510

13,766,440

13,441,116

Revisions of previous estimates (in BOE) | Boe

(390,330)

^[1]

(247,350)

^[2]

2,806,181

^[3]

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

132,884

Sales of minerals in place (in BOE) | Boe

(184,722)

(2,254,038)

Production (sales volumes) (in BOE) | Boe

(452,786)

(177,742)

(226,819)

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

12,446,394

13,289,510

13,766,440

Proved developed reserves (in BOE) | Boe

7,349,626

7,970,562

10,089,861

8,032,809

Proved undeveloped reserves (in BOE) | Boe

5,096,768

5,318,948

3,676,579

5,408,307

Delhi Field

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

Positive revision of previous estimate (in BOE) | Boe

1,679,481

Crude Oil

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

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

10,526,344

12,782,755

11,638,618

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

(64,074)

^[1]

(1,919,052)

^[2]

1,826,053

^[3]

17,146

Sales of minerals in place (in Bbls/Mcf)

(184,722)

(485,536)

Production (sales volumes) (in Bbls/Mcf)

(450,294)

(169,783)

(196,380)

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

10,011,976

10,526,344

12,782,755

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

Proved developed reserves (in Bbls/Mcf)

7,347,231

7,858,224

10,077,522

7,670,934

Proved undeveloped reserves (in Bbls/Mcf)

2,664,745

2,668,120

2,705,233

3,967,684

Crude Oil | Delhi Field

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

1,817,224

Natural Gas Liquids

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

2,278,688

979,885

492,473

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

156,195

^[1]

1,269,588

^[2]

975,515

^[3]

32,731

Sales of minerals in place (in Bbls/Mcf)

(480,832)

Production (sales volumes) (in Bbls/Mcf)

(1,288)

(3,516)

(7,271)

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

2,433,595

2,278,688

979,885

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)

1,572

32,164

8,539

111,978

Proved undeveloped reserves (in Bbls/Mcf)

2,432,023

2,246,524

971,346

380,495

Revision due to improved design (in Bbls/Mcf)

^[1]

185,499

Natural Gas Liquids | Delhi Field

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

Revision due to improved design (in Bbls/Mcf)

1,275,178

Natural Gas Liquids | Giddings Field

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