Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Sep. 07, 2016 | Dec. 31, 2015 | |
Document and Entity Information | |||
Entity Registrant Name | EVOLUTION PETROLEUM CORP | ||
Entity Central Index Key | 1,006,655 | ||
Current Fiscal Year End Date | --06-30 | ||
Entity Filer Category | Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Jun. 30, 2016 | ||
Document Fiscal Year Focus | 2,016 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 32,905,982 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 116,929,484 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Current assets | ||
Cash and cash equivalents | $ 34,077,060 | $ 20,118,757 |
Receivables | 2,638,188 | 3,122,473 |
Deferred tax asset | 105,321 | 82,414 |
Derivative assets, net | 14,132 | 0 |
Prepaid expenses and other current assets | 251,749 | 369,404 |
Total current assets | 37,086,450 | 23,693,048 |
Property and equipment, net of depreciation, depletion, and amortization | ||
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization | 59,970,463 | 45,186,886 |
Other property and equipment, net | 28,649 | 276,756 |
Total property and equipment, net | 59,999,112 | 45,463,642 |
Other assets | 365,489 | 726,037 |
Total assets | 97,451,051 | 69,882,727 |
Current liabilities | ||
Accounts payable | 5,809,107 | 8,173,878 |
Accrued liabilities and other | 2,097,951 | 855,373 |
Derivative liabilities, net | 0 | 109,974 |
State and federal taxes payable | 621,850 | 190,032 |
Total current liabilities | 8,528,908 | 9,329,257 |
Long term liabilities | ||
Deferred income taxes | 11,840,693 | 11,242,551 |
Asset retirement obligations | 760,300 | 715,767 |
Deferred rent | 0 | 18,575 |
Total liabilities | 21,129,901 | 21,306,150 |
Commitments and contingencies (Note 18) | ||
Stockholders' equity | ||
Preferred stock, par value $0.001; 5,000,000 shares authorized: 8.5% Series A Cumulative Preferred Stock, 1,000,000 shares designated, 317,319 shares issued and outstanding at June 30, 2016 and 2015, respectively, with a total liquidation preference of $7,932,975 ($25.00 per share) | 317 | 317 |
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,907,863 and 32,845,205 shares as of June 30, 2016 and 2015, respectively | 32,907 | 32,845 |
Additional paid-in capital | 47,171,563 | 36,847,289 |
Retained earnings | 29,116,363 | 11,696,126 |
Total stockholders' equity | 76,321,150 | 48,576,577 |
Total liabilities and stockholders' equity | $ 97,451,051 | $ 69,882,727 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Preferred stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Preferred stock, shares authorized | 5,000,000 | 5,000,000 |
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, issued shares | 32,907,863 | 32,845,205 |
Common stock, outstanding shares | 32,907,863 | 32,845,205 |
Series A Cumulative Preferred Stock | ||
Preferred stock, shares authorized | 1,000,000 | 1,000,000 |
Cumulative Preferred Stock (as a percent) | 8.50% | 8.50% |
Preferred stock, shares issued | 317,319 | 317,319 |
Preferred stock, shares outstanding | 317,319 | 317,319 |
Preferred stock, total liquidation preference (in dollars) | $ 7,932,975 | $ 7,932,975 |
Preferred stock, liquidation preference (in dollars per share) | $ 25 | $ 25 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) | 12 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Revenues | ||||
Total revenues | $ 26,349,502 | $ 27,841,265 | $ 17,673,508 | |
Operating costs | ||||
Production costs | 9,062,179 | 9,335,244 | 1,193,573 | |
Depreciation, depletion and amortization | 5,165,120 | 3,615,737 | 1,228,685 | |
Accretion of discount on asset retirement obligations | 49,054 | 34,866 | 41,626 | |
General and administrative expenses | [1] | 9,079,597 | 6,256,783 | 8,388,291 |
Restructuring charges | 1,257,433 | (5,431) | 1,293,186 | |
Total operating costs | 24,684,315 | 19,257,568 | 12,145,361 | |
Income from operations | 1,665,187 | 8,583,697 | 5,528,147 | |
Other | ||||
Gain on settled derivative instruments, net | 3,315,123 | 0 | 0 | |
Gain (loss) on unsettled derivative instruments, net | 124,106 | (109,974) | 0 | |
Delhi field litigation settlement | 28,096,500 | 0 | 0 | |
Delhi field insurance recovery related to pre-reversion event | 1,074,957 | 0 | 0 | |
Interest and other income | 26,211 | 35,991 | 30,256 | |
Interest (expense) | (70,943) | (73,636) | (69,092) | |
Income before income tax provision | 34,231,141 | 8,436,078 | 5,489,311 | |
Income tax provision | 9,570,779 | 3,444,221 | 1,891,998 | |
Net income attributable to the Company | 24,660,362 | 4,991,857 | 3,597,313 | |
Dividends on preferred stock | 674,302 | 674,302 | 674,302 | |
Net income attributable to common shareholders | $ 23,986,060 | $ 4,317,555 | $ 2,923,011 | |
Earnings per common share | ||||
Basic (in dollars per share) | $ 0.73 | $ 0.13 | $ 0.09 | |
Diluted (in dollars per share) | $ 0.73 | $ 0.13 | $ 0.09 | |
Weighted average number of common shares outstanding | ||||
Basic (in shares) | 32,810,375 | 32,817,456 | 30,895,832 | |
Diluted (in shares) | 32,861,231 | 32,924,018 | 32,564,067 | |
Crude Oil | ||||
Revenues | ||||
Total revenues | $ 26,130,762 | $ 27,761,291 | $ 17,460,392 | |
Natural Gas Liquids | ||||
Revenues | ||||
Total revenues | 7,885 | 37,227 | 117,166 | |
Natural Gas | ||||
Revenues | ||||
Total revenues | 2,895 | 26,601 | 95,950 | |
Artificial Lift Technology | ||||
Revenues | ||||
Total revenues | 207,960 | 16,146 | 0 | |
Operating costs | ||||
Production costs | $ 70,932 | $ 20,369 | $ 0 | |
[1] | General and administrative expenses for the years ended June 30, 2016, 2015 and 2014 included non-cash stock-based compensation expense of $1,750,209, $943,653, and $1,352,322, respectively. These years also included litigation expenses of $2,729,755, $1,015,105, and $300,564, respectively. |
Consolidated Statements of Ope5
Consolidated Statements of Operations (Parenthetical) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Non-cash stock-based compensation expense | $ 1,750,209 | $ 943,653 | $ 1,352,322 |
General and Administrative Expense | |||
Non-cash stock-based compensation expense | 1,750,209 | 943,653 | 1,352,322 |
Litigation expense | $ 2,729,755 | $ 1,015,105 | $ 300,564 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Cash Flows From Operating Activities | |||
Net income attributable to the Company | $ 24,660,362 | $ 4,991,857 | $ 3,597,313 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depreciation, depletion and amortization | 5,211,494 | 3,664,373 | 1,272,778 |
Impairments included in restructuring charge | 569,228 | 0 | 0 |
Stock-based compensation | 1,750,209 | 943,653 | 1,352,322 |
Stock-based compensation related to restructuring | 59,339 | 0 | 376,365 |
Accretion of discount on asset retirement obligations | 49,054 | 34,866 | 41,626 |
Settlement of asset retirement obligations | 0 | (223,564) | (315,952) |
Deferred income taxes | 575,235 | 1,422,489 | 1,344,812 |
Deferred rent | 0 | (17,145) | (17,145) |
(Gain) loss on derivative instruments, net | (3,439,229) | 109,974 | 0 |
Noncash (gain) on Delhi field litigation settlement | (596,500) | 0 | 0 |
Write-off of deferred loan costs | 50,414 | 0 | 0 |
Changes in operating assets and liabilities: | |||
Receivables | 484,285 | (1,665,261) | 507,592 |
Prepaid expenses and other current assets | 24,754 | 378,049 | (480,899) |
Accounts payable and accrued expenses | 822,730 | 551,452 | 663,645 |
Income taxes payable | 431,818 | 190,032 | (233,548) |
Net cash provided by operating activities | 30,653,193 | 10,380,775 | 8,108,909 |
Cash flows from investing activities | |||
Derivative settlements received | 3,633,831 | 0 | 0 |
Proceeds from asset sales | 0 | 398,242 | 542,347 |
Development of oil and natural gas properties | (21,095,901) | (4,890,909) | (966,931) |
Acquisitions of oil and natural gas properties | 0 | 0 | (59,315) |
Capital expenditures for technology and other equipment | (6,883) | (313,059) | (312,890) |
Maturities of certificates of deposit | 0 | 0 | 250,000 |
Other assets | (161,345) | (236,559) | (202,017) |
Net cash used by investing activities | (17,630,298) | (5,042,285) | (748,806) |
Cash flows from financing activities | |||
Proceeds from the exercise of stock options | 51,000 | 141,600 | 3,252,801 |
Acquisitions of treasury stock | (1,357,185) | (333,841) | (1,655,251) |
Common stock dividends paid | (6,565,823) | (9,833,642) | (9,723,833) |
Preferred stock dividends paid | (674,302) | (674,302) | (674,302) |
Deferred loan costs | (168,972) | (94,075) | (63,535) |
Tax benefits related to stock-based compensation | 9,650,657 | 1,633,946 | 509,096 |
Other | 33 | 67 | 6,850 |
Net cash provided (used) by financing activities | 935,408 | (9,160,247) | (8,348,174) |
Net increase (decrease) in cash and cash equivalents | 13,958,303 | (3,821,757) | (988,071) |
Cash and cash equivalents, beginning of year | 20,118,757 | 23,940,514 | 24,928,585 |
Cash and cash equivalents, end of year | $ 34,077,060 | $ 20,118,757 | $ 23,940,514 |
Consolidated Statement of Chang
Consolidated Statement of Changes in Stockholders' Equity - USD ($) | Total | Preferred | Common Stock | Additional Paid-in Capital | Retained Earnings | Treasury Stock |
Balance at Jun. 30, 2013 | $ 54,836,161 | $ 317 | $ 29,410 | $ 31,813,239 | $ 24,013,035 | $ (1,019,840) |
Balance (in shares) at Jun. 30, 2013 | 317,319 | 28,608,969 | ||||
Increase (Decrease) in Stockholders' Equity | ||||||
Issuance of restricted common stock | $ 40 | (40) | ||||
Issuance of restricted common stock (shares) | 39,732 | |||||
Exercise of warrants | $ 905 | (905) | ||||
Exercise of warrants (in shares) | 905,391 | |||||
Exercise of stock options | 3,871,407 | $ 3,299 | 3,868,108 | |||
Exercise of stock options (shares) | 3,299,367 | |||||
Forfeiture of restricted stock | $ (51) | 51 | ||||
Forfeiture of restricted stock (in shares) | (51,099) | |||||
Acquisition of treasury stock | $ (2,273,857) | (2,273,857) | ||||
Acquisitions of treasury stock (shares) | (186,714) | (186,714) | ||||
Retirements of treasury stock | $ (988) | (3,292,709) | 3,293,697 | |||
Stock-based compensation | $ 1,728,687 | 1,728,687 | ||||
Tax benefits related to stock-based compensation | 509,096 | 509,096 | ||||
Net income | 3,597,313 | 3,597,313 | ||||
Common stock cash dividends | (9,723,833) | (9,723,833) | ||||
Preferred stock cash dividends | (674,302) | (674,302) | ||||
Recovery of short swing profits | 6,850 | 6,850 | ||||
Balance at Jun. 30, 2014 | 51,877,522 | $ 317 | $ 32,615 | 34,632,377 | 17,212,213 | 0 |
Balance (in shares) at Jun. 30, 2014 | 317,319 | 32,615,646 | ||||
Increase (Decrease) in Stockholders' Equity | ||||||
Issuance of restricted common stock | 67 | $ 214 | (147) | |||
Issuance of restricted common stock (shares) | 213,466 | |||||
Exercise of stock options | $ 141,600 | $ 87 | 141,513 | |||
Exercise of stock options (shares) | 87,000 | 87,000 | ||||
Acquisition of treasury stock | $ (504,124) | (504,124) | ||||
Acquisitions of treasury stock (shares) | (70,907) | |||||
Retirements of treasury stock | $ (71) | (504,053) | 504,124 | |||
Stock-based compensation | 943,653 | 943,653 | ||||
Tax benefits related to stock-based compensation | 1,633,946 | 1,633,946 | ||||
Net income | 4,991,857 | 4,991,857 | ||||
Common stock cash dividends | (9,833,642) | (9,833,642) | ||||
Preferred stock cash dividends | (674,302) | (674,302) | ||||
Balance at Jun. 30, 2015 | 48,576,577 | $ 317 | $ 32,845 | 36,847,289 | 11,696,126 | 0 |
Balance (in shares) at Jun. 30, 2015 | 317,319 | 32,845,205 | ||||
Increase (Decrease) in Stockholders' Equity | ||||||
Issuance of restricted common stock | 33 | $ 272 | (239) | |||
Issuance of restricted common stock (shares) | 272,098 | |||||
Exercise of stock options | $ 127,500 | $ 50 | 127,450 | |||
Exercise of stock options (shares) | 50,000 | 50,000 | ||||
Forfeiture of restricted stock | $ (41) | 41 | ||||
Forfeiture of restricted stock (in shares) | (40,758) | |||||
Acquisition of treasury stock | $ (1,263,402) | (1,263,402) | ||||
Acquisitions of treasury stock (shares) | (218,682) | |||||
Retirements of treasury stock | $ (219) | (1,263,183) | 1,263,402 | |||
Stock-based compensation | 1,809,548 | 1,809,548 | ||||
Tax benefits related to stock-based compensation | 9,650,657 | 9,650,657 | ||||
Net income | 24,660,362 | 24,660,362 | ||||
Common stock cash dividends | (6,565,823) | (6,565,823) | ||||
Preferred stock cash dividends | (674,302) | (674,302) | ||||
Balance at Jun. 30, 2016 | $ 76,321,150 | $ 317 | $ 32,907 | $ 47,171,563 | $ 29,116,363 | $ 0 |
Balance (in shares) at Jun. 30, 2016 | 317,319 | 32,907,863 |
Organization and Basis of Prepa
Organization and Basis of Preparation | 12 Months Ended |
Jun. 30, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Basis of Preparation | Organization and Basis of Preparation Nature of Operations. Evolution Petroleum Corporation ("EPM") and its subsidiaries (the "Company", "we", "our" or "us"), is an independent petroleum company headquartered in Houston, Texas and incorporated under the laws of the State of Nevada. We are engaged primarily in the development of oil and gas reserves within known oil and gas resources utilizing conventional and proprietary technology. Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. As a result of the separation of our GARP ® artificial lift technology operations discussed in Note 8, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified as appropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues included crude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells that utilized the technology, together with service revenues derived from the use of the Company’s technology in third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oil and gas production costs and cost of artificial lift technology services. Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents. Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of joint interest owner obligations due within 30 days of the invoice date, accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2016 and 2015 , no allowance for doubtful accounts was considered necessary. Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized. Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent , and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 -month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Tests did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2016 , 2015 or 2014 . Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furniture and equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years . The assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred. Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense. Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricing model to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fair value is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that the recipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service. Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment. Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues. Derivative Instruments. The Company uses derivative transactions to reduce its exposure to oil price volatility. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to a ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as a result of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes. Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computer equipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment. Intangible Assets - Intellectual Property. The Company has capitalized the external costs, consisting primarily of legal costs, related to securing its patents and trademarks. The costs related to patents were amortized over the remaining patent life which was less than the expected useful life of each patent. Trademarks have a perpetual life and were not amortized. Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense. Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common shares outstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants, and contingent restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method. Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shall be assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPS computation. Potentially dilutive common shares are excluded from the computation if their effect is anti-dilutive. Recent Accounting Pronouncements. In August 2015, the FASB issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 would have been effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provided for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements, if any. In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” as part of their simplification initiatives. The standard requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The update is effective for public company annual reporting periods beginning after December 15, 2016, and may be adopted prospectively or retrospectively with early adoption permitted. The Company plans to early adopt this standard the first quarter of year ended June 30, 2017 and does not believe that adoption of this update will have a material impact on our results of operations, financial position or cash flows. On February 25, 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than 12 months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our condensed consolidated financial statements. On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company plans to early adopt this standard during the first quarter of the year ended June 30, 2017. The adoption of this standard will result in all excess tax benefits or deficiencies being recognized as tax expense or benefit in the reporting period they occur regardless of whether the benefit reduces taxes payable in the current period. On the statement of cash flows excess tax benefits or deficiencies will be classified along with other income tax as an operating activity and cash paid by the Company when directly withholding shares for tax withholding purposes will continue to be classified as a financing activity. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements, but does not expect the impact of adoption to be material. |
Dehli Field Litigation Settleme
Dehli Field Litigation Settlement | 12 Months Ended |
Jun. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Dehli Field Litigation Settlement | Delhi Field Litigation Settlement On June 24, 2016, Evolution Petroleum Corporation, together with its subsidiaries NGS Sub Corp. and Tertiaire Resources Company (collectively, “Evolution”), entered into a settlement agreement with Denbury Resources, Inc. and Denbury Onshore, LLC, a subsidiary of Denbury Resources Inc. (together with Denbury Onshore, "Denbury"), to resolve all outstanding disputes and claims between the parties, including claims related to the litigation between Evolution and Denbury with respect to the Delhi field in northeastern Louisiana. The Delhi field litigation between the parties has been dismissed by the Court with prejudice. In connection with this settlement, the Company recognized a $28.1 million settlement gain consisting of a $27.5 million cash payment made by Denbury together with its conveyance to Evolution of a 23.9% working interest in the Mengel Sand Interval, a separate interval within the boundaries of the Delhi field which is not currently producing and for which we estimated a Level 2 fair value of $596,500 . In addition, effective July 1, 2016, Denbury will be credited with an additional 0.2226% overriding royalty interest in the Delhi field to remedy a previous dispute regarding the interests conveyed in the original transaction between the parties. See Note 18 — Commitments and Contingencies. |
Receivables
Receivables | 12 Months Ended |
Jun. 30, 2016 | |
Receivables [Abstract] | |
Receivables | Receivables As of June 30, 2016 and June 30, 2015 our receivables consisted of the following: June 30, June 30, Receivables from oil and gas sales $ 2,637,593 $ 3,122,155 Other 595 318 Total receivables $ 2,638,188 $ 3,122,473 |
Prepaid Expenses and Other Curr
Prepaid Expenses and Other Current Assets | 12 Months Ended |
Jun. 30, 2016 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Prepaid Expenses and Other Current Assets | Prepaid Expenses and Other Current Assets As of June 30, 2016 and June 30, 2015 our prepaid expenses and other current assets consisted of the following: June 30, June 30, Prepaid insurance $ 168,681 $ 178,994 Prepaid federal and state income taxes — 22,542 Equipment inventory (a) — 81,538 Retainers and deposits 30,568 26,978 Other prepaid expenses 52,500 59,352 Prepaid expenses and other current assets $ 251,749 $ 369,404 (a) As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged to restructuring costs as part of the separation of our artificial lift technology operations. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Jun. 30, 2016 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment As of June 30, 2016 and June 30, 2015 , our oil and natural gas properties and other property and equipment consisted of the following: June 30, June 30, Oil and natural gas properties: Property costs subject to amortization $ 77,408,353 $ 57,718,653 Less: Accumulated depreciation, depletion, and amortization (17,437,890 ) (12,531,767 ) Unproved properties not subject to amortization — — Oil and natural gas properties, net 59,970,463 45,186,886 Other property and equipment: Furniture, fixtures and office equipment, at cost 228,752 287,680 Artificial lift technology equipment, at cost 7,000 319,994 Less: Accumulated depreciation (207,103 ) (330,918 ) Other property and equipment, net $ 28,649 $ 276,756 As of June 30, 2016 and 2015 , all oil and gas property costs were being amortized. During the year ended June 30, 2016 , the Company incurred capital expenditures of $19.0 million for the Delhi field, including approximately $16.4 million for the NGL plant project which is currently under construction. We have incurred $21.5 million on a cumulative basis for the NGL plant out of a total authorized commitment of $24.6 million , with a remaining balance of approximately $3.1 million . As described in Note 3 – Delhi Field Litigation Settlement, we received a 23.9% working interest in the Mengel Interval (currently non-producing) having an estimated fair value of $596,500 . On December 31, 2015, as described in Note 8 — Restructuring, we transferred our residual artificial lift technology equipment to new entity not controlled by the Company. We recorded a charge of $210,392 to expense most of the remaining capitalized costs of artificial lift equipment installed in the wells of a third-party customer. Under our installation contracts, we had funded the majority of the incremental equipment and installation costs in exchange for 25% of the net profits from production, as defined, for as long as the technology remains in the wells. During the year ended ended June 30, 2015, we incurred $217,733 of costs related to installing our artificial lift technology on third party wells and recorded an impairment charge of $275,682 reflecting the unrecovered installation costs, net of estimated salvage value. During the year ended June 30, 2014, we incurred $377,943 of installation costs. Impairment charges are included in depreciation, depletion and amortization expense on the consolidated statement of operations. On October 24, 2014, we sold all of our remaining mineral interest and assets in the Mississippi Lime project for proceeds of $389,165 and the buyer's assumption of all abandonment liabilities. On December 1, 2013, we sold our producing assets and undeveloped reserves in the Lopez Field in South Texas in return for proceeds of $402,500 and the buyer's assumption of all abandonment liabilities. The net proceeds from these sales of our properties, including the reduction of asset retirement obligations, were recognized as a reduction of the cost of oil and gas properties. |
Other Assets
Other Assets | 12 Months Ended |
Jun. 30, 2016 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Other Assets | Other Assets As of June 30, 2016 and June 30, 2015 our other assets consisted of the following: June 30, June 30, Royalty rights 108,512 — Less: Accumulated amortization of royalty rights (6,782 ) — Investment in Well Lift Inc., at cost 108,750 — Deferred loan costs 168,972 337,078 Less: Accumulated amortization of deferred loan costs (13,963 ) (147,057 ) Trademarks — 44,803 Patent costs — 538,276 Less: Accumulated amortization of patent costs — (47,063 ) Other assets, net $ 365,489 $ 726,037 During the year ended June 30, 2016 , our previous negotiations to obtain a new expanded secured credit facility were curtailed due to market conditions. As a result, the Company determined that $50,414 of deferred legal fees related to the proposed facility were unlikely to be utilized and were charged to expense. In addition, $107,196 of deferred costs incurred for title work in the Delhi field was charged to capitalized costs of oil and gas properties. Our existing unsecured credit facility expired in April 2016 and its associated deferred loan costs of $179,468 had been completely amortized. Contemporaneous with that facility's expiration, we entered into a secured credit facility provided by another financial institution, incurring $168,972 of deferred loan costs. Total amortization of costs related to our credit facilities for the year ended June 30, 2016 was $46,374 . See Note 8 – Restructuring for discussion of transactions associated with the separation of our artificial lift technology operations. The company accounts for its investment in Well Lift Inc. ("WLI") using the cost method under which any return of capital reduces cost and any dividends paid are recorded as income. This investment is considered a level 3 fair value measurement and its value will be evaluated for impairment periodically and when management identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the investment. |
Restructuring
Restructuring | 12 Months Ended |
Jun. 30, 2016 | |
Restructuring and Related Activities [Abstract] | |
Restructuring | Restructuring Separation of GARP ® Artificial Lift Technology Operations During the quarter ended December 31, 2015, we conducted a strategic review of our GARP ® artificial lift technology operations and consummated a plan to separate and transfer these operations to a new entity controlled by the inventor of the technology, our former Senior Vice President of Operations, and certain former employees of the Company. We invested $108,750 in common and preferred stock of the new entity, WLI. We own 17.5% of WLI and our former employees that previously had primary responsibility for our GARP ® operations own the balance of the common stock. Our preferred stock is convertible at our option into common stock which would result in our ownership of 42.5% of WLI, based on the current capital structure of WLI. The company has no contractual exposure to losses of WLI, nor does it have any obligation or agreement to provide additional funding or support to WLI if it is needed. In connection with this transaction, three employees of the Company were terminated. We accrued a restructuring charge based on agreements with the employees covering salary and benefit continuation and an acceleration of vesting of equity awards in exchange for release from liabilities and other provisions including agreements not to compete. At December 31, 2015, we recorded a personnel restructuring charge of $688,205 consisting of $59,339 in stock-based compensation and $628,866 of accrued separation and benefits expense. Our current estimate of remaining restructuring obligations as of June 30, 2016 is as follows: Type of Cost December 31, Payments Adjustments to Cost June 30, Salary expense $ 530,387 $ (176,796 ) $ — $ 353,591 Payroll taxes and benefits expense 98,479 (32,582 ) — 65,897 Accrued liability for restructuring costs $ 628,866 $ (209,378 ) $ — $ 419,488 Other Restructuring Impairments Also in connection with the December 2015 separation of GARP ® , we and WLI entered into an agreement under which we transferred our technology assets, including our patents and trademarks, to WLI in exchange for a perpetual royalty of 5% on all future gross revenues associated with the GARP ® technology. We reduced the carrying value of these exchanged technology assets to our estimate of their expected discounted net present value, which was $108,512 . This estimate was based on the recent financial results from our artificial lift technology operations and the current depressed state of the oil and gas industry and the potential upside cases were assigned relatively low probabilities for accounting purposes. This resulted in an impairment charge of $469,395 . In addition, we transferred certain inventory and minor fixed assets to WLI which had no further use in our operations and were deemed to have negligible market or salvage value. This resulted in impairments of $92,901 to equipment inventory and $6,932 to fixed assets, respectively. These impairments total $569,228 and are included in restructuring charges. Restructuring of Oil and Gas Operations On November 1, 2013, we undertook an initiative to refocus our business that resulted in an adjustment of our workforce with less emphasis on engineering and greater emphasis on sales and marketing. In exchange for severance and non-compete agreements with the terminated employees, we recorded a restructuring charge of $1,332,186 representing $376,365 of stock-based compensation from the accelerated vesting of equity awards and $955,821 of estimated severance compensation and benefits to be paid during the twelve months ended December 31, 2014. All of the Company's obligations under these agreements had been fulfilled at December 31, 2014, extinguishing the liability. Our disposition of the accrued restructuring charges is reflected in the following schedule: Type of Cost Balance at December 31, Payments Adjustment to Cost June 30, Salary expense $ 615,721 $ (615,721 ) $ — $ — Incentive compensation costs 185,525 (185,525 ) — — Payroll taxes and benefits expense 154,575 (110,144 ) (44,431 ) — Accrued liability for restructuring costs $ 955,821 $ (911,390 ) $ (44,431 ) $ — |
Accrued Liabilities and Other
Accrued Liabilities and Other | 12 Months Ended |
Jun. 30, 2016 | |
Other Liabilities Disclosure [Abstract] | |
Accrued Liabilities and Other | Accrued Liabilities and Other As of June 30, 2016 and June 30, 2015 our other current liabilities consisted of the following: June 30, June 30, Accrued incentive and other compensation $ 999,172 $ 578,910 Accrued restructuring charges 419,488 — Asset retirement obligations due within one year 201,896 57,223 Accrued royalties, including suspended accounts 49,580 75,164 Accrued franchise taxes 62,834 94,885 Payable for settled derivatives 318,708 — Accrued - other 46,273 49,191 Accrued liabilities and other $ 2,097,951 $ 855,373 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Jun. 30, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligation for the years ended June 30, 2016 and 2015 : Years Ended 2016 2015 Asset retirement obligations—beginning of period $ 772,990 $ 352,215 Liabilities incurred (a) 28,505 564,019 Liabilities settled — (137,604 ) Liabilities sold — (52,526 ) Accretion of discount 49,054 34,866 Revisions to previous estimates 111,647 12,020 Asset retirement obligations — end of period 962,196 772,990 Less: current asset retirement obligations (201,896 ) (57,223 ) Long-term portion of asset retirement obligations $ 760,300 $ 715,767 (a) Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Jun. 30, 2016 | |
Equity [Abstract] | |
Stockholders' Equity | Stockholders' Equity Common Stock Commencing in December 2013, the Board of Directors initiated a quarterly cash dividend on our common stock at a quarterly rate of $0.10 per share and subsequently adjusted this rate to $0.05 per share during the quarter ended March 31, 2015. We paid cash dividends of $6,565,823 , $9,833,642 and $9,723,833 from retained earnings to our common shareholders during the years ended June 30, 2016 , 2015 and 2014 , respectively. On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Since commencement in June 2015, we have repurchased 265,762 shares at an average price of $6.05 per share, for total cost of $1,609,008 . This includes 202,390 shares purchased during the year ended June 30, 2016, at an average price of $5.80 , for total cost of $1,173,899 . Under the program's terms, shares are repurchased only on the open market and in accordance with the requirements of the Securities and Exchange Commission. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors, including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time. We have not repurchased any shares since December 2015. During the year ended June 30, 2014, we issued (i) 1,568,832 shares of our common stock upon the exercise of incentive stock options (ISOs), receiving cash proceeds totaling $3,252,801 , and (ii) 2,635,696 of our common shares upon cashless exercises of nonqualified stock options ("NQSOs") and incentive warrants, all being exercised on a net basis, except for 50,956 of previously acquired shares owned by option holders that were swapped in payment of the exercise price. The weighted average cost of these swapped shares was $12.14 . In fiscal 2014, we retired 801,889 shares of treasury stock acquired in previous fiscal years at a cost of $1,019,840 and 186,714 treasury shares acquired during fiscal 2014 from employees and directors at an average cost of $12.18 per share or $2,273,857 . The shares acquired in 2014 were received in satisfaction of payroll tax liabilities from the exercise of stock options and vesting of restricted stock (requiring cash outlays by us) and 50,956 shares were received from option holders in cashless stock option exercises, using stock previously owned by the option holder. Series A Cumulative Perpetual Preferred Stock At June 30, 2016 , there were 317,319 shares of the Company’s 8.5% Series A Cumulative (perpetual) Preferred Stock outstanding. The Series A Cumulative Preferred Stock cannot be converted into our common stock and there are no sinking fund or redemption rights available to the holders thereof. Effective July 1, 2014, we can redeem this preferred stock at any time for the stated liquidation value of $25.00 per share plus accrued dividends. With respect to dividend rights and rights upon our liquidation, winding-up or dissolution, the Series A Preferred Stock ranks senior to our common stockholders, but subordinate to any of our existing and future debt. Dividends on the Series A Cumulative Preferred Stock accrue and accumulate at a fixed rate of 8.5% per annum on the $25.00 per share liquidation preference, payable monthly at $0.177083 per share, as, if and when declared by our Board of Directors through its Dividend Committee. We paid dividends of $674,302 to holders of our Series A Preferred Stock during each of the years ended June 30, 2016 , 2015 , and 2014 . Tax Treatment of Dividends to Recipients Based on our current projections for the fiscal year ending June 30, 2016 , we expect all preferred and common dividends for this fiscal year will be treated for tax purposes as qualified dividend income to the recipients. For the fiscal year ended June 30, 2015 , 100% of cash dividends on preferred stock were treated as qualified dividend income. For the same period, approximately 86% of cash dividends on common shares were treated as a return of capital to stockholders and the remainder of 14% were treated as qualified dividend income. For fiscal year ended June 30, 2014 , all cash dividends on preferred and common stock were treated for tax purposes as a return of capital to our shareholders. |
Stock-Based Incentive Plan
Stock-Based Incentive Plan | 12 Months Ended |
Jun. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Incentive Plan | Stock-Based Incentive Plan Under the terms of the Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan (the "Plan"), we have granted option awards to purchase common stock (the "Stock Options"), restricted common stock awards ("Restricted Stock"), contingent restricted common stock awards ("Contingent Restricted Stock") and/or unrestricted fully vested common stock, to employees, directors, and consultants of the Company. The Plan authorizes the issuance of 6,500,000 shares of common stock prior to its expiration on October 24, 2017 and 282,133 shares remain available for grant as of June 30, 2016 . Stock Options and Incentive Warrants No Stock Options have been granted since August 2008 and all compensation costs attributable to Stock Options have been recognized in prior periods. No Incentive Warrants have been granted since February 2006. All compensation costs attributable to these awards have been recognized in prior periods and all remaining awards were exercised in November 2013. The following summary presents information regarding outstanding Stock Options as of June 30, 2016 , and the changes during the period: Number of Stock Options Weighted Average Exercise Price Aggregate Intrinsic Value(1) Weighted Average Remaining Contractual Term (in years) Stock Options outstanding at July 1, 2015 91,061 $ 2.50 Exercised (50,000 ) 2.55 Expired (5,830 ) 4.02 Stock Options outstanding at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Vested at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Exercisable at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 (1) Based upon the difference between the market price of our common stock on the last trading date of the period ( $5.47 as of June 30, 2016 ) and the Stock Option exercise price of in-the-money Stock Options. For the year ended June 30, 2016 , there were 50,000 Stock Options exercised with an aggregate intrinsic value of $131,000 . For the year ended June 30, 2015, there were 87,000 Stock Options exercised, with an aggregate intrinsic value of $501,810 . For the year ended June 30, 2014, there were 4,644,759 Stock Options and Incentive Warrants exercised with an aggregate intrinsic value of $47,504,114 . No stock options vested during the years ended June 30, 2016 , 2015 , and 2014 . Restricted Stock and Contingent Restricted Stock Prior to August 28, 2014, all Restricted Stock grants contained a four -year vesting period based solely on service. Restricted Stock which vests based solely on service is valued at the fair market value on the date of grant and are amortized over the service period. In August 2014 and in December 2015, the Company awarded grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after four years if unvested, contain service-based, performance-based and market-based vesting provisions. The common shares underlying the Restricted Stock grants were issued on the date of grant, whereas the Contingent Restricted Stock are reserved from the Plan, but will be issued only upon the attainment of specified performance-based or market-based vesting provisions. Performance-based grants vest upon the attainment of earnings, revenue and other operational goals and require that the recipient remain an employee of the Company through the vesting date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the four -year term. As of June 30, 2016 , certain performance-based awards were not considered probable of vesting for accounting purposes and no compensation expense has been recognized with regard to these awards. If these awards are later determined to be probable of vesting, cumulative compensation expense would be recorded at that time and amortization would continue over the remaining expected vesting period. Market-based awards entitle employees to vest in a fixed number of shares when the three-year trailing total return on the Company’s common stock exceeds the corresponding total returns of various quartiles of companies comprising the SIG Exploration and Production Index (NASDAQ EPX) during defined measurement periods. The fair value and expected vesting period of these awards were determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. During the fiscal year ended June 30, 2016 , we granted market-based awards with fair values ranging from $2.93 to $5.07 , all with an expected vesting period of 3.83 years, based on the various quartiles of comparative market performance. During the fiscal year ended June 30, 2015, we granted market-based awards with fair values ranging from $4.26 to $8.40 and with expected vesting periods of 3.30 years to 2.55 years, based on the various quartiles of comparative market performance. Compensation expense for market-based awards is recognized over the expected vesting period using the straight-line method, so long as the award holder remains an employee of the Company. Total compensation expense is based on the fair value of the awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service. In December 2015, one employee resigned and three others left the Company when we restructured our artificial lift technology operations. As a result 31,467 restricted shares and 14,212 contingent restricted shares were forfeited. Also in connection with the restructuring, at the Company’s request in February 2016, certain employees agreed to voluntarily relinquish 31,307 restricted performance-based shares and 15,654 contingent performance-based shares in exchange for 22,016 shares of service-based restricted stock subject to vesting in three annual tranches ending on August 28, 2018. Unvested Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Service-based awards 224,515 $ 7.08 Performance-based awards 89,079 7.17 Market-based awards 93,254 5.50 Unvested at June 30, 2016 406,848 $ 6.74 The following table sets forth the Restricted Stock transactions for the year ended June 30, 2016 : Number of Restricted Shares Weighted Average Grant-Date Fair Value Unamortized Compensation Expense at June 30, 2016 Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 262,227 $ 9.37 $ — Service-based awards granted 164,610 5.84 Performance-based awards granted 64,752 6.09 Market-based awards granted 64,752 4.58 Vested (86,719 ) 8.73 Forfeited (62,774 ) 9.72 Unvested at June 30, 2016 406,848 $ 6.74 $ 1,536,125 2.6 During the years ended June 30, 2016 , 2015 , and 2014 , there were 86,719 , 91,306 , and 277,198 shares of Restricted Stock that vested with a total grant date fair value of $757,229 , $766,970 , and $1,796,243 , respectively. Unvested Contingent Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Performance-based awards 44,542 $ 7.17 Market-based awards 46,630 3.34 Unvested at June 30, 2016 91,172 $ 5.21 The following table summarizes Contingent Restricted Stock activity: Number of Weighted Unamortized Compensation Expense at June 30, 2016 (1) Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 56,286 $ 8.20 Performance-based awards granted 32,376 6.09 Market-based awards granted 32,376 2.93 Forfeited (29,866 ) $ 9.33 Unvested at June 30, 2016 91,172 $ 5.21 $ 107,219 2.8 (1) Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes. Stock-based Compensation Expense For the years ended June 30, 2016 , 2015 , and 2014 , we recognized stock-based compensation expense related to Restricted Stock, Contingent Restricted Stock grants, and Stock Option grants of $1,809,548 , $943,653 , and $1,728,687 , respectively. Included in these amounts are stock-based compensation expense of $59,339 for the year ended June 30, 2016 and $376,365 for the year ended June 30, 2014 that were reflected in restructuring charges. |
Supplemental Disclosure of Cash
Supplemental Disclosure of Cash Flow Information | 12 Months Ended |
Jun. 30, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Disclosure of Cash Flow Information | Supplemental Disclosure of Cash Flow Information Our supplemental disclosures of cash flow information for the years ended June 30, 2016 , 2015 , and 2014 are as follows: June 30, 2016 2015 2014 Income taxes paid $ 540,000 $ 220,000 $ 755,941 Income tax refunds 1,556,999 331,733 — Non-cash transactions: Increase (decrease) in accrued purchases of property and equipment (2,250,048 ) 5,422,566 (183,766 ) Deferred loan costs charged to oil and gas property costs 107,196 — — Oil and natural gas property costs attributable to the recognition of asset retirement obligations 140,151 576,039 66,976 Mengel working interest acquired in Delhi Field litigation settlement 596,500 — — Royalty rights acquired through non-monetary exchange of patent and trademark assets 108,512 — — Previously acquired Company shares swapped by holders to pay stock option exercise price $ 76,500 $ — $ 618,606 Accrued purchases of treasury stock (170,283 ) 170,283 — |
Income Taxes
Income Taxes | 12 Months Ended |
Jun. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits during the years ended June 30, 2016 , 2015 and 2014 . We believe that we have appropriate support for the income tax positions taken and to be taken on the Company's tax returns and that the accruals for tax liabilities are adequate for all open years based on our assessment of many factors including past experience and interpretations of tax law applied to the facts of each matter. The Company's tax returns are open to audit under the statute of limitations for the years ending June 30, 2013 through June 30, 2015 for federal tax purposes and for the years ended June 30, 2011 through June 30, 2015 for state tax purposes. The components of our income tax provision (benefit) are as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current: Federal $ 8,731,290 $ 1,413,296 $ 386,018 State 264,254 608,436 161,168 Total current income tax provision 8,995,544 2,021,732 547,186 Deferred: Federal 541,891 1,282,059 1,319,727 State 33,344 140,430 25,085 Total deferred income tax provision 575,235 1,422,489 1,344,812 $ 9,570,779 $ 3,444,221 $ 1,891,998 The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate, currently 34% , to the income tax provision in our financial statements. The effective tax rate for 2016 is less than the statutory rate primarily due to the benefit derived from statutory depletion in excess of tax basis. The effective tax rates for 2015 and 2014 exceed the statutory rate as a result of state income taxes, primarily in the state of Louisiana, with smaller adjustments related to stock-based compensation and other permanent differences. June 30, 2016 June 30, 2015 June 30, 2014 Income tax provision (benefit) computed at the statutory federal rate $ 11,638,588 $ 2,868,267 $ 1,866,366 Reconciling items: Depletion in excess of basis (2,242,620 ) — — State income taxes, net of federal tax benefit 196,415 595,708 189,081 Permanent differences related to stock-based compensation — — (155,817 ) Other permanent differences (21,604 ) (19,754 ) (7,632 ) Income tax provision $ 9,570,779 $ 3,444,221 $ 1,891,998 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred tax assets and liabilities are classified as either current or noncurrent on the balance sheet based on the classification of the related asset or liability for financial reporting purposes. Deferred tax assets and liabilities not related to specific assets or liabilities on the financial statements are classified according to the expected reversal date of the temporary difference or the expected utilization date for tax attribute carryforwards. Asset (Liability) June 30, 2016 June 30, 2015 June 30, 2014 Deferred tax assets: Non-qualified stock-based compensation $ 553,182 $ 173,647 $ 134,469 Net operating loss carry-forwards 386,808 400,288 427,249 AMT credit carry-forward* — 701,254 701,254 Other 130,947 91,113 165,775 Gross deferred tax assets 1,070,937 1,366,302 1,428,747 Valuation allowance (292,446 ) (292,446 ) (292,446 ) Total deferred tax assets 778,491 1,073,856 1,136,301 Deferred tax liability: Oil and natural gas properties (12,513,863 ) (12,233,993 ) (10,873,949 ) Total deferred tax liability (12,513,863 ) (12,233,993 ) (10,873,949 ) Net deferred tax liability $ (11,735,372 ) $ (11,160,137 ) $ (9,737,648 ) _______________________________________________________________________________ * In fiscal 2016 we used our total AMT credit carry-forward of $901,545 . Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation. The above assets and liabilities are present on the balance sheet as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current deferred tax asset $ 105,321 $ 82,414 $ 159,624 Non-current deferred tax liability 11,840,693 11,242,551 9,897,272 Net liability 11,735,372 11,160,137 9,737,648 As of June 30, 2016 , we had a federal tax loss carryforward of approximately $1.2 million that we acquired through the reverse merger in May 2004. The majority of the tax loss carryforwards from the reverse merger expired without being utilized. We will be able to utilize a maximum of $0.3 million of these carryforwards in equal annual amounts of $39,648 through 2023 and the balance is not able to be utilized based on the provisions of IRC Section 382. We have recorded a valuation allowance for the portion of our net operating loss that is limited by IRC Section 382. During fiscal 2016 we utilized the remaining amount of $25.3 million of net operating losses ("NOL's") created primarily from tax deductions in excess of book deductions related to the exercise of non-qualified stock options and incentive warrants in fiscal 2014. NOL's related to such stock-based awards had not affected our future tax provision for financial reporting purposes, nor had it been recognized as a deferred tax asset for these future benefits. In fiscal 2016, 2015 and 2014, we recognized a tax benefit for utilization of these NOL's to offset cash taxes that would otherwise have been payable as an increase in additional paid in capital, in amounts of $9,650,657 , $1,633,946 and $509,096 respectively. In late September 2015, we received a $1.5 million refund payment of cash taxes paid to the State of Louisiana over a three-year period ended June 30, 2014. We also received $57,467 from the State of Louisiana for interest on the refund and recorded it as a reduction of current income tax expense. This carryback of tax losses resulted from the exercise of stock options and incentive warrants in fiscal 2014 and, accordingly, we recognized this benefit as an increase in additional paid-in capital for financial reporting purposes. This carryback utilized approximately $19.1 million of an estimated $24.2 million net loss for state tax purposes. The remaining balance of this net loss carryforward in Louisiana was utilized in the tax return for the year ended June 30, 2015. In addition, as of June 30, 2016, the Company has an estimated carryforward of percentage depletion in excess of basis of approximately $5.0 million . These future deductions are limited to 65% of taxable income in any period. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Jun. 30, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions On June 30, 2011, we entered into a Technology Assignment Agreement with the Company’s Senior Vice President of Operations to acquire exclusive, perpetual, non-cancelable rights to the patented artificial lift technology he developed while employed by the Company. Under the agreement, he was paid a fee when the technology was employed. For the years ended June 30, 2016, 2015 and 2014, we made payments of $0 , $26,579 and $10,113 , respectively, under the agreement, while he served as an officer of the Company. Our obligations with respect to this agreement were terminated in December 2015 in connection with the transfer of our artificial lift technology operations to Well Lift Inc. |
Net Income Per Share
Net Income Per Share | 12 Months Ended |
Jun. 30, 2016 | |
Earnings Per Share [Abstract] | |
Net Income Per Share | Net Income Per Share The following table sets forth the computation of basic and diluted net income per share: June 30, 2016 2015 2014 Numerator Net income attributable to common shareholders $ 23,986,060 $ 4,317,555 $ 2,923,011 Denominator Weighted average number of common shares – Basic 32,810,375 32,817,456 30,895,832 Effect of dilutive securities: Contingent restricted stock grants 9,378 4,422 — Stock Options 41,478 102,140 1,668,235 Total weighted average dilutive securities 50,856 106,562 1,668,235 Weighted average number of common shares and dilutive potential common shares used in diluted EPS 32,861,231 32,924,018 32,564,067 Net income per common share – Basic $ 0.73 $ 0.13 $ 0.09 Net income per common share – Diluted $ 0.73 $ 0.13 $ 0.09 The following were reflected in the calculation of diluted earnings per share as of June 30, 2016 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 91,172 Stock Options 2.19 35,231 Total $ 0.61 126,403 The following were reflected in the calculation of diluted earnings per share as of June 30, 2015 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 56,286 Stock Options $ 2.50 91,061 Total $ 1.55 147,347 The following were reflected in the calculation of diluted earnings per share as of June 30, 2014 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Stock Options $ 2.08 178,061 |
Credit Agreements
Credit Agreements | 12 Months Ended |
Jun. 30, 2016 | |
Debt Disclosure [Abstract] | |
Credit Agreements | Credit Agreements Senior Secured Credit Agreement On April 11, 2016, the Company entered into a new three -year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million . The Facility replaces the Company's previous unsecured credit facility which was set to expire on April 29, 2016 and was terminated in early April. The initial borrowing base under the Facility was set at $10 million and the Company has no outstanding borrowings. Proceeds from the Facility may be used for the acquisition and development of oil and gas properties and for letters of credit and other general corporate purposes. Availability of borrowings under the Facility is subject to semi-annual borrowing base redeterminations. The Facility included a placement fee of 0.50% on the initial borrowing base, amounting to $50,000 , and carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either Libor plus 2.75% or the Prime Rate, as defined, plus 1.00% . The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00 to 1.00 , (b) a debt service coverage ratio of not less than 1.10 to 1.00 , and (c) a consolidated tangible net worth of not less than $40 million , all as defined under the Facility. In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance in debt issuance costs related to the Facility was $155,009 as of June 30, 2016. Unsecured Revolving Credit Agreement On February 29, 2012, the Company and a commercial bank entered into an unsecured credit agreement with a four year term. The agreement had provided $5 million of availability, which the Company never utilized. The original expiration date was extended to April 29, 2016. In connection with this agreement, the Company had incurred $179,468 of debt issuance costs. Such costs had been capitalized in Other Assets and have been completely amortized to expense. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Jun. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies On December 13, 2013, Evolution Petroleum Corporation and its wholly-owned subsidiaries, Tertiaire Resources Company and NGS Sub. Corp. (collectively, “Evolution”) filed a lawsuit in the 133 rd Judicial District Court of Harris County, Texas, against Denbury Onshore, LLC (“Denbury”) alleging breaches of certain 2006 agreements between the parties regarding the Delhi field in northeast Louisiana. On June 24, 2016, Evolution entered into a settlement agreement with Denbury to resolve all outstanding disputes and claims between the parties, including claims related to the pending litigation between Evolution and Denbury with respect to the Delhi field. Pursuant to the settlement, the parties dismissed with prejudice all such claims between them with respect to such litigation. In addition to clarifying certain aspects of the parties' ongoing relationship, the settlement resolves (a) claims by Evolution in connection with the June 2013 incident at the Delhi field involving a release of well fluids (the “June 2013 Incident”); (b) disputes regarding the occurrence, determination, timing, nature and terms of “payout” and Evolution's related reversionary interest in the Delhi Field; and (c) any claims by Denbury related to the purchase by Denbury of its original Delhi field interest from the Company. Under the terms of the settlement, Evolution retains any and all rights under its existing agreements with Denbury regarding indemnification for any costs which are asserted or arise subsequent to the effective date of the settlement and which relate to periods prior to reversion of its working interest, including any such costs related to the June 2013 Incident. See Note 3 — Delhi Field Litigation Settlement. On December 3, 2013, our wholly owned subsidiary, NGS Sub Corp., was served with a lawsuit filed in the 8th Judicial District Court of Winn Parish, Louisiana by Cecil M. Brooks and Brandon Hawkins, residents of Louisiana, alleging that in 2006 a former subsidiary of NGS Sub Corp. improperly disposed of water from an off-lease well into a well located on the plaintiffs’ lands in Winn Parish. The plaintiffs requested monetary damages and other relief. NGS Sub Corp. divested its ownership of the property in question along with its ownership of the subsidiary in 2008 to a third party. The district court granted our exception of no right of action and dismissed certain claims against NGS Sub Corp. The plaintiffs subsequently filed an amended petition naming NGS Sub Corp. and the Company as defendants. NGS Sub Corp. and the Company have denied the plaintiffs’ claims. Various pretrial motions filed on behalf of multiple parties were recently decided by the court and discovery is in process. We will continue to vigorously defend all claims by plaintiffs and consider the likelihood of a material loss to the Company in this matter to be remote. Lease Commitments. We had a non-cancelable lease for office space that expired on July 31, 2016. Late in fiscal 2016, the Company entered into a new non-cancelable office space with a three year term ending on May 31, 2019. Future minimum lease commitments as of June 30, 2016 under these operating leases are as follows: For the fiscal year ended June 30, 2017 $ 80,235 2018 73,073 2019 66,984 Total $ 220,292 Rent expense for the years ended June 30, 2016 , 2015 , and 2014 was $182,626 , $175,103 , and $174,229 , respectively. Capital Expenditures. See Note 6 for discussion of capital projects in progress and expected remaining capital commitments. |
Concentrations of Credit Risk
Concentrations of Credit Risk | 12 Months Ended |
Jun. 30, 2016 | |
Risks and Uncertainties [Abstract] | |
Concentrations of Credit Risk | Concentrations of Credit Risk Major Customers. We market all of our oil and natural gas production from the properties we operate. We do not currently market our share of crude oil production from Delhi. Although we have the right to take our working interest production at Delhi in-kind, we are currently selling our oil under the Delhi operator's agreement with Plains Marketing L.P. for the delivery of our oil to a pipeline at the field. The majority of our operated gas, oil and condensate production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more our net oil and natural gas revenues during the years ended June 30, 2016 , 2015 , and 2014 . The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be expected to have a material adverse effect on our operations. Year Ended June 30, Customer 2016 2015 2014 Plains Marketing L.P. (includes Delhi production) 99 % 99 % 96 % Enterprise Crude Oil LLC — % — % 2 % Flint Hills — % — % 1 % ETC Texas Pipeline, LTD. — % — % 1 % All others 1 % 1 % — % Total 100 % 100 % 100 % Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales to third parties in the oil and natural gas industry. Our concentration of customers in this industry may impact our overall credit risk. Cash and Cash Equivalents and Certificates of Deposit. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents in high quality money market funds. At times, cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation ("FDIC"). Our certificates of deposit are below or at the maximum federally insured limit set by the FDIC. |
Retirement Plan
Retirement Plan | 12 Months Ended |
Jun. 30, 2016 | |
Compensation and Retirement Disclosure [Abstract] | |
Retirement Plan | Retirement Plan We have a Company sponsored 401(k) Retirement Plan ("Plan") which covers all full-time employees. We currently match 100% of employees' contributions to the Plan, to a maximum of the first 6% of each participant's eligible compensation, with Company contributions fully vested when made. Our matching contributions to the Plan totaled $88,348 , $85,676 , and $116,873 for the years ended June 30, 2016 , 2015 , and 2014 , respectively. |
Derivatives
Derivatives | 12 Months Ended |
Jun. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives | Derivatives In early June 2015, the Company began using derivative instruments to reduce its exposure to crude oil price volatility for a substantial portion of its near-term forecasted production. The Company's objectives for this program were to achieve a more predictable level of cash flows to support the Company’s capital expenditure program and to provide better financial visibility for the payment of dividends on common stock. The Company uses both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. While these derivative instruments are intended to limit the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The Company does not intend to enter into derivative instruments for speculative or trading purposes. The Company accounts for derivatives under the provisions of ASC 815 Derivatives and Hedgin g ("ASC 815") under which the Company records the fair value of the instruments on the balance sheet at each reporting date, with changes in fair value recognized in income. Given cost and complexity considerations, the Company did not elect to use cash flow hedge accounting provided under ASC 815. Under cash flow hedge accounting, the effective portion of the change in fair value of the derivative instruments would be deferred in other comprehensive income and not recognized in earnings until the underlying hedged item impacts earnings. These derivative instruments can result in both fair value asset and liability positions held with each counterparty. These positions are offset to a single net fair value asset or liability at the end of each reporting period. The Company nets its fair value amounts of derivative instruments executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The fair value derivative instruments where the Company is in a net asset position with its counterparty as of June 30, 2016 totaled $14,132 . Refer to Note 22–Fair Value Measurement for derivative asset and derivative liability balances before offsetting. The Company monitors the credit rating of its counterparties and believes it does not have significant credit risk. Accordingly, we do not currently require our counterparties to post collateral to support the net asset positions of our derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. For the year ended June 30, 2016, the Company recorded in the consolidated statement of operations a gain on derivative instruments of $3,439,229 consisting of a realized gain of $3,315,123 on settled derivatives and an unrealized gain of $124,106 on unsettled derivatives. For the year ended June 30, 2015 , the Company recorded in the consolidated statement of operations a net unrealized loss on unsettled derivatives of $109,974 . The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2016 . Period Type of Contract Volumes (in Bbls./day) Weighted Average Floor Price per Bbl. Weighted Average Ceiling Price per Bbl. Weighted Average Collar Spread per Bbl. Months of July 2016 through September 2016 Costless Collar 600 $45.00 $55.00 $10.00 Subsequent to June 30, 2016 , the Company's July and August collars expired without settlement as the respective NYMEX prices for those months fell between the floor and ceiling prices. |
Fair Value Measurement
Fair Value Measurement | 12 Months Ended |
Jun. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurement | Fair Value Measurement Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities. Level 2—Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3—Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities. Fair Value of Derivative Instruments. The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2016 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: June 30, 2016 Asset (Liability) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheets Current derivative assets $ 45,263 $ (31,131 ) $ 14,132 Current derivative liabilities (31,131 ) 31,131 — Total $ 14,132 $ — $ 14,132 The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. The fair values are also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparties credit quality for derivative assets and the Company’s credit quality for derivative liabilities. To date, adjustments for credit quality have not had a material impact on the fair values. |
Supplemental Disclosures about
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) | 12 Months Ended |
Jun. 30, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) | Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) Costs incurred for oil and natural gas property acquisition, exploration and development activities The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $140,151 , $576,039 and $66,976 during the years ended June 30, 2016 , 2015 , and 2014 , respectively. For the Years Ended June 30, 2016 2015 2014 Oil and Natural Gas Activities Property acquisition costs: Proved property $ — $ — $ — Unproved property (a) 596,500 — 47,344 Exploration costs — — 757,423 Development costs 19,093,200 10,975,637 18,566 Total costs incurred for oil and natural gas activities $ 19,689,700 $ 10,975,637 $ 823,333 (a) As described in Note 3 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500 . This cost is included in properties subject to amortization. Estimated Net Quantities of Proved Oil and Natural Gas Reserves The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2016 , 2015 , and 2014 , which requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce. Proved oil and natural gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows: Crude Oil (Bbls) Natural Gas Liquids (Bbls) Natural Gas (Mcf) BOE Proved developed and undeveloped reserves: June 30, 2013 12,782,755 979,885 22,797 13,766,440 Revisions of previous estimates (a) (1,919,052 ) 1,269,588 2,412,677 (247,350 ) Improved recovery, extensions and discoveries 17,146 32,731 498,044 132,884 Sales of minerals in place (184,722 ) — — (184,722 ) Production (sales volumes) (169,783 ) (3,516 ) (26,655 ) (177,742 ) June 30, 2014 10,526,344 2,278,688 2,906,863 13,289,510 Revisions of previous estimates (b) (64,074 ) 156,195 (2,894,703 ) (390,330 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (450,294 ) (1,288 ) (7,221 ) (452,786 ) June 30, 2015 10,011,976 2,433,595 4,939 12,446,394 Revisions of previous estimates (c) (765,385 ) (198,233 ) (3,319 ) (964,171 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (658,041 ) (491 ) (1,620 ) (658,802 ) June 30, 2016 8,588,550 2,234,871 — 10,823,421 Proved developed reserves: June 30, 2013 10,077,522 8,539 22,797 10,089,861 June 30, 2014 7,858,224 32,164 481,042 7,970,562 June 30, 2015 7,347,231 1,572 4,939 7,349,626 June 30, 2016 7,168,249 — — 7,168,249 Proved undeveloped reserves: June 30, 2013 2,705,233 971,346 — 3,676,579 June 30, 2014 2,668,120 2,246,524 2,425,821 5,318,948 June 30, 2015 2,664,745 2,432,023 — 5,096,768 June 30, 2016 1,420,301 2,234,871 — 3,655,172 (a) Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO 2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes. (b) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well. (c) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period. Standardized Measure of Discounted Future Net Cash Flows Future oil and natural gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas ("ASC 932"). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves. The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2016 , 2015 , and 2014 are as follows: For the Years Ended June 30, 2016 2015 2014 Future cash inflows $ 383,491,193 $ 807,030,282 $ 1,193,515,075 Future production costs and severance taxes (179,182,565 ) (309,225,333 ) (475,387,931 ) Future development costs (16,595,047 ) (49,691,006 ) (46,154,178 ) Future income tax expenses (45,713,438 ) (123,888,665 ) (195,581,510 ) Future net cash flows 142,000,143 324,225,278 476,391,456 10% annual discount for estimated timing of cash flows (64,042,824 ) (165,028,739 ) (250,313,784 ) Standardized measure of discounted future net cash flows $ 77,957,319 $ 159,196,539 $ 226,077,672 Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials. Year Ended June 30, 2016 2015 2014 Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) NYMEX prices used in determining future cash flows $ 42.91 n/a $ 71.88 $ 3.44 $ 100.37 $ 4.10 There were no natural gas reserves in 2016. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant. A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows: For the Years Ended June 30, 2016 2015 2014 Balance, beginning of year $ 159,196,539 $ 226,077,672 $ 307,220,699 Net changes in sales prices and production costs related to future production (120,832,747 ) (88,043,095 ) (73,439,526 ) Changes in estimated future development costs 74,991 (9,585,405 ) 9,848,614 Sales of oil and gas produced during the period, net of production costs (17,079,363 ) (18,538,016 ) (16,479,934 ) Net change due to extensions, discoveries, and improved recovery — — 775,574 Net change due to revisions in quantity estimates (18,821,014 ) (9,391,321 ) (23,757,788 ) Net change due to sales of minerals in place — — (3,150,277 ) Development costs incurred during the period 16,327,883 7,785,095 — Accretion of discount 21,870,650 31,974,540 45,896,187 Net change in discounted income taxes 36,598,239 34,157,767 58,073,450 Net changes in timing of production and other (a) 622,141 (15,240,698 ) (78,909,327 ) Balance, end of year $ 77,957,319 $ 159,196,539 $ 226,077,672 (a) Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014. |
Selected Quarterly Financial Da
Selected Quarterly Financial Data (Unaudited) | 12 Months Ended |
Jun. 30, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Selected Quarterly Financial Data (Unaudited) | Selected Quarterly Financial Data (Unaudited) The following table presents summarized quarterly financial information for the years ended June 30, 2016 and 2015 : 2016 First Second (1) Third Fourth (2) Revenues $ 7,379,406 $ 6,622,927 $ 5,106,735 $ 7,240,434 Operating income (loss) 1,846,498 (454,987 ) (681,147 ) 954,823 Net income (loss) available to common shareholders $ 2,923,652 $ 654,697 $ (298,183 ) $ 20,705,894 Basic net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 Diluted net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 2015 First Second (3) Third Fourth Revenues $ 4,004,827 $ 7,708,067 $ 7,064,689 $ 9,063,682 Operating income 1,840,866 2,162,294 1,245,990 3,334,547 Net income available to common shareholders $ 960,435 $ 1,071,342 $ 566,011 $ 1,719,767 Basic net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 Diluted net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 (1) Includes $1.3 million restructuring charge. (2) Includes gain on settlement of Delhi field litigation of $28.1 million . (3) Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field. |
Summary of Significant Accoun32
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Jun. 30, 2016 | |
Accounting Policies [Abstract] | |
Principles of Consolidation and Reporting | Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EPM and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous year include certain reclassifications that were made to conform to the current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. As a result of the separation of our GARP ® artificial lift technology operations discussed in Note 8, previously reported revenues for the Delhi field and our artificial lift technology operations have been reclassified as appropriate to crude oil, natural gas liquids, natural gas and artificial lift technology service revenues. Before the reclassification, artificial lift technology revenues included crude oil, natural gas liquids and gas revenues produced by certain of the Company’s operated wells that utilized the technology, together with service revenues derived from the use of the Company’s technology in third party wells. Previously reported production costs for our artificial lift technology operations have been reclassified as appropriate to oil and gas production costs and cost of artificial lift technology services. |
Use of Estimates | Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents. |
Accounts Receivable and Allowance for Doubtful Accounts | Account Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of joint interest owner obligations due within 30 days of the invoice date, accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish provisions for losses on accounts receivables if it is determined that collection of all or a part of an outstanding balance is not probable. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2016 and 2015 , no allowance for doubtful accounts was considered necessary. |
Oil and Natural Gas Properties | Oil and Natural Gas Properties. We use the full cost method of accounting for our investments in oil and natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the project is evaluated and proved reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural gas properties is transferred to capitalized costs being amortized. |
Limitation on Capitalized Costs | Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion and amortization or as a credit to oil and natural gas properties. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent , and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 -month period prior to the end of the reporting period (with consideration of price changes only to the extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Tests did not result in an impairment of our oil and natural gas properties during the years ended June 30, 2016 , 2015 or 2014 . |
Other Property and Equipment | Other Property and Equipment. Other property and equipment includes leasehold improvements, data processing and telecommunications equipment, office furniture and equipment, and oilfield service equipment related to our artificial lift technology operations. These items are recorded at cost and depreciated over expected lives of the individual assets or group of assets, which range from three to seven years . The assets are depreciated using the straight-line method, except for oilfield service equipment related to our artificial lift technology operations, which is depreciated using a method which approximates the timing and amounts of expected revenues from the contract. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. Repairs and maintenance costs are expensed in the period incurred. |
Deferred Financing Costs | Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. |
Asset Retirement Obligations | Asset Retirement Obligations. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset retirement cost is considered a level 3 fair value measurement. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment. |
Fair Value of Financial Instruments | Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, certificates of deposit, accounts receivable, accounts payable and derivative instruments. Except for derivatives, the carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. The fair values of the Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data obtained from third-party sources, including quoted forward prices for oil and gas, discount rates and volatility factors. |
Stock-based Compensation | Stock-based Compensation. Estimated grant date fair value of stock-based compensation awards is determined to provide the basis for future compensation expense. Service-and performance-based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. For market-based awards, which reflect future returns of our common stock, the fair value and expected vesting period are determined using a Monte Carlo simulation based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies comprising a benchmark index. We used the Black-Scholes option-pricing model to determine grant date fair value of our past Stock Option and Incentive Warrant awards. For service-based awards stock-based compensation equal to grant date fair value is recognized ratably over the requisite service period as the award vests. A performance-based award vests upon attaining the award's operational goal and requires that the recipient remain an employee of the Company upon vesting. Stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the performance goal will be achieved. The expected vesting period may be deemed to be shorter than the remainder of the award’s term. For a market-based award stock-based compensation expense equal to grant date fair value is recognized ratably over the expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination of service. |
Revenue Recognition | Revenue Recognition - Oil and Gas. We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment. Revenue Recognition - Artificial Lift Technology. Our artificial lift technology operations have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues. |
Derivative Instruments | Derivative Instruments. The Company uses derivative transactions to reduce its exposure to oil price volatility. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty pursuant to a ISDA master agreement, which provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price volatility, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, net gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain or (loss) on derivatives in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from the counterparty as a result of derivative settlements are classified as cash flows from investing activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes. |
Depreciation, Depletion and Amortization | Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves. Other property, consisting of leasehold improvements, office and computer equipment, vehicles and artificial lift equipment is depreciated as described above in Other Property and Equipment. |
Intangible Assets - Intellectual Property | Intangible Assets - Intellectual Property. The Company has capitalized the external costs, consisting primarily of legal costs, related to securing its patents and trademarks. The costs related to patents were amortized over the remaining patent life which was less than the expected useful life of each patent. Trademarks have a perpetual life and were not amortized. |
Income Taxes | Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may result in taxable or deductible amounts in future years. The measurement of deferred tax assets may be reduced by a valuation allowance based upon management's assessment of available evidence if it is deemed more likely than not some or all of the deferred tax assets will not be realizable. We recognize a tax benefit from an uncertain position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position and will record the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax expense. |
Earnings (loss) per share | Earnings (loss) per share. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss by the weighted-average number of common shares outstanding. The computation of diluted EPS is similar to the computation of basic EPS, except that the denominator is increased to include the number of additional common shares that would have been outstanding if potential dilutive common shares had been issued. Our potential dilutive common shares are our outstanding stock options, warrants, and contingent restricted common stock. The dilutive effect of our potential dilutive common shares is reflected in diluted EPS by application of the treasury stock method. Under the treasury stock method, exercise of stock options and warrants shall be assumed at the beginning of the period (or at time of issuance, if later) and common shares shall be assumed to be issued; the proceeds from exercise shall be assumed to be used to purchase common stock at the average market price during the period; and the incremental shares (the difference between the number of shares assumed issued and the number of shares assumed purchased) shall be included in the denominator of the diluted EPS computation. Potentially dilutive common shares are excluded from the computation if their effect is anti-dilutive. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements. In August 2015, the FASB issued Accounting Standards Update 2015-14, which defers the effective date of ASU 2014-09 Revenue from Contracts with Customers (Topic 606) (" ASU 2014-09") one year, and would allow entities the option to early adopt the new revenue standard as of the original effective date. Issued in May 2014, ASU 2014-09 provided guidance on revenue recognition on contracts with customers to transfer goods or services or on contracts for the transfer of nonfinancial assets. ASU 2014-09 requires that revenue recognition on contracts with customers depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. For public companies, ASU 2014-09 would have been effective for fiscal years, and interim periods within those years, beginning after December 15, 2017. The standard provided for either the retrospective or cumulative effect transition method. The Company is currently assessing the impact of the adoption of ASU 2014-09 will have on its consolidated financial statements, if any. In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes” as part of their simplification initiatives. The standard requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The update is effective for public company annual reporting periods beginning after December 15, 2016, and may be adopted prospectively or retrospectively with early adoption permitted. The Company plans to early adopt this standard the first quarter of year ended June 30, 2017 and does not believe that adoption of this update will have a material impact on our results of operations, financial position or cash flows. On February 25, 2016, the FASB issued ASU 2016-02, Leases (“ASU 2016-02”), which relates to the accounting for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and obligations created by leases with lease terms of more than 12 months. In addition, this standard requires both lessees and lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are evaluating the impact the adoption of ASU 2016-02 will have on our condensed consolidated financial statements. On March 30, 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation: Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”) , which relates to the accounting for employee share-based payments. This standard addresses several aspects of the accounting for share-based payment award transactions, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. This standard will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The Company plans to early adopt this standard during the first quarter of the year ended June 30, 2017. The adoption of this standard will result in all excess tax benefits or deficiencies being recognized as tax expense or benefit in the reporting period they occur regardless of whether the benefit reduces taxes payable in the current period. On the statement of cash flows excess tax benefits or deficiencies will be classified along with other income tax as an operating activity and cash paid by the Company when directly withholding shares for tax withholding purposes will continue to be classified as a financing activity. The Company is in the process of evaluating the impact of this accounting standard on its consolidated financial statements, but does not expect the impact of adoption to be material. |
Receivables (Tables)
Receivables (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Receivables [Abstract] | |
Schedule of receivables | As of June 30, 2016 and June 30, 2015 our receivables consisted of the following: June 30, June 30, Receivables from oil and gas sales $ 2,637,593 $ 3,122,155 Other 595 318 Total receivables $ 2,638,188 $ 3,122,473 |
Prepaid Expenses and Other Cu34
Prepaid Expenses and Other Current Assets (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of prepaid expenses and other current assets | As of June 30, 2016 and June 30, 2015 our prepaid expenses and other current assets consisted of the following: June 30, June 30, Prepaid insurance $ 168,681 $ 178,994 Prepaid federal and state income taxes — 22,542 Equipment inventory (a) — 81,538 Retainers and deposits 30,568 26,978 Other prepaid expenses 52,500 59,352 Prepaid expenses and other current assets $ 251,749 $ 369,404 (a) As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged to restructuring costs as part of the separation of our artificial lift technology operations |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Property, Plant and Equipment [Abstract] | |
Schedule of oil and natural gas properties and other property and equipment | As of June 30, 2016 and June 30, 2015 , our oil and natural gas properties and other property and equipment consisted of the following: June 30, June 30, Oil and natural gas properties: Property costs subject to amortization $ 77,408,353 $ 57,718,653 Less: Accumulated depreciation, depletion, and amortization (17,437,890 ) (12,531,767 ) Unproved properties not subject to amortization — — Oil and natural gas properties, net 59,970,463 45,186,886 Other property and equipment: Furniture, fixtures and office equipment, at cost 228,752 287,680 Artificial lift technology equipment, at cost 7,000 319,994 Less: Accumulated depreciation (207,103 ) (330,918 ) Other property and equipment, net $ 28,649 $ 276,756 |
Other Assets (Tables)
Other Assets (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |
Schedule of other assets | As of June 30, 2016 and June 30, 2015 our other assets consisted of the following: June 30, June 30, Royalty rights 108,512 — Less: Accumulated amortization of royalty rights (6,782 ) — Investment in Well Lift Inc., at cost 108,750 — Deferred loan costs 168,972 337,078 Less: Accumulated amortization of deferred loan costs (13,963 ) (147,057 ) Trademarks — 44,803 Patent costs — 538,276 Less: Accumulated amortization of patent costs — (47,063 ) Other assets, net $ 365,489 $ 726,037 |
Restructuring (Tables)
Restructuring (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Restructuring and Related Activities [Abstract] | |
Schedule of restructuring reserve by type of cost | Our current estimate of remaining restructuring obligations as of June 30, 2016 is as follows: Type of Cost December 31, Payments Adjustments to Cost June 30, Salary expense $ 530,387 $ (176,796 ) $ — $ 353,591 Payroll taxes and benefits expense 98,479 (32,582 ) — 65,897 Accrued liability for restructuring costs $ 628,866 $ (209,378 ) $ — $ 419,488 Our disposition of the accrued restructuring charges is reflected in the following schedule: Type of Cost Balance at December 31, Payments Adjustment to Cost June 30, Salary expense $ 615,721 $ (615,721 ) $ — $ — Incentive compensation costs 185,525 (185,525 ) — — Payroll taxes and benefits expense 154,575 (110,144 ) (44,431 ) — Accrued liability for restructuring costs $ 955,821 $ (911,390 ) $ (44,431 ) $ — |
Accrued Liabilities and Other (
Accrued Liabilities and Other (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Other Liabilities Disclosure [Abstract] | |
Other Current Liabilities | As of June 30, 2016 and June 30, 2015 our other current liabilities consisted of the following: June 30, June 30, Accrued incentive and other compensation $ 999,172 $ 578,910 Accrued restructuring charges 419,488 — Asset retirement obligations due within one year 201,896 57,223 Accrued royalties, including suspended accounts 49,580 75,164 Accrued franchise taxes 62,834 94,885 Payable for settled derivatives 318,708 — Accrued - other 46,273 49,191 Accrued liabilities and other $ 2,097,951 $ 855,373 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of reconciliation of the beginning and ending asset retirement obligation | The following is a reconciliation of the beginning and ending asset retirement obligation for the years ended June 30, 2016 and 2015 : Years Ended 2016 2015 Asset retirement obligations—beginning of period $ 772,990 $ 352,215 Liabilities incurred (a) 28,505 564,019 Liabilities settled — (137,604 ) Liabilities sold — (52,526 ) Accretion of discount 49,054 34,866 Revisions to previous estimates 111,647 12,020 Asset retirement obligations — end of period 962,196 772,990 Less: current asset retirement obligations (201,896 ) (57,223 ) Long-term portion of asset retirement obligations $ 760,300 $ 715,767 (a) Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest. |
Stock-Based Incentive Plan (Tab
Stock-Based Incentive Plan (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Summary of information regarding outstanding Stock Options and Incentive Warrants and the changes during the fiscal year | The following summary presents information regarding outstanding Stock Options as of June 30, 2016 , and the changes during the period: Number of Stock Options Weighted Average Exercise Price Aggregate Intrinsic Value(1) Weighted Average Remaining Contractual Term (in years) Stock Options outstanding at July 1, 2015 91,061 $ 2.50 Exercised (50,000 ) 2.55 Expired (5,830 ) 4.02 Stock Options outstanding at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Vested at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 Exercisable at June 30, 2016 35,231 $ 2.19 $ 115,558 1.2 (1) Based upon the difference between the market price of our common stock on the last trading date of the period ( $5.47 as of June 30, 2016 ) and the Stock Option exercise price of in-the-money Stock Options. |
Schedule of Restricted Stock transactions | The following table sets forth the Restricted Stock transactions for the year ended June 30, 2016 : Number of Restricted Shares Weighted Average Grant-Date Fair Value Unamortized Compensation Expense at June 30, 2016 Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 262,227 $ 9.37 $ — Service-based awards granted 164,610 5.84 Performance-based awards granted 64,752 6.09 Market-based awards granted 64,752 4.58 Vested (86,719 ) 8.73 Forfeited (62,774 ) 9.72 Unvested at June 30, 2016 406,848 $ 6.74 $ 1,536,125 2.6 Unvested Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Service-based awards 224,515 $ 7.08 Performance-based awards 89,079 7.17 Market-based awards 93,254 5.50 Unvested at June 30, 2016 406,848 $ 6.74 Unvested Contingent Restricted Stock awards at June 30, 2016 consisted of the following: Award Type Number of Weighted Performance-based awards 44,542 $ 7.17 Market-based awards 46,630 3.34 Unvested at June 30, 2016 91,172 $ 5.21 The following table summarizes Contingent Restricted Stock activity: Number of Weighted Unamortized Compensation Expense at June 30, 2016 (1) Weighted Average Remaining Amortization Period (Years) Unvested at July 1, 2015 56,286 $ 8.20 Performance-based awards granted 32,376 6.09 Market-based awards granted 32,376 2.93 Forfeited (29,866 ) $ 9.33 Unvested at June 30, 2016 91,172 $ 5.21 $ 107,219 2.8 (1) Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes. |
Supplemental Disclosure of Ca41
Supplemental Disclosure of Cash Flow Information (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Schedule of supplemental disclosures of cash flow information | Our supplemental disclosures of cash flow information for the years ended June 30, 2016 , 2015 , and 2014 are as follows: June 30, 2016 2015 2014 Income taxes paid $ 540,000 $ 220,000 $ 755,941 Income tax refunds 1,556,999 331,733 — Non-cash transactions: Increase (decrease) in accrued purchases of property and equipment (2,250,048 ) 5,422,566 (183,766 ) Deferred loan costs charged to oil and gas property costs 107,196 — — Oil and natural gas property costs attributable to the recognition of asset retirement obligations 140,151 576,039 66,976 Mengel working interest acquired in Delhi Field litigation settlement 596,500 — — Royalty rights acquired through non-monetary exchange of patent and trademark assets 108,512 — — Previously acquired Company shares swapped by holders to pay stock option exercise price $ 76,500 $ — $ 618,606 Accrued purchases of treasury stock (170,283 ) 170,283 — |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Income Tax Disclosure [Abstract] | |
Schedule of components of income tax provision (benefit) | The components of our income tax provision (benefit) are as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current: Federal $ 8,731,290 $ 1,413,296 $ 386,018 State 264,254 608,436 161,168 Total current income tax provision 8,995,544 2,021,732 547,186 Deferred: Federal 541,891 1,282,059 1,319,727 State 33,344 140,430 25,085 Total deferred income tax provision 575,235 1,422,489 1,344,812 $ 9,570,779 $ 3,444,221 $ 1,891,998 |
Schedule of reconciliation of statutory income tax expense to income tax provision | The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate, currently 34% , to the income tax provision in our financial statements. The effective tax rate for 2016 is less than the statutory rate primarily due to the benefit derived from statutory depletion in excess of tax basis. The effective tax rates for 2015 and 2014 exceed the statutory rate as a result of state income taxes, primarily in the state of Louisiana, with smaller adjustments related to stock-based compensation and other permanent differences. June 30, 2016 June 30, 2015 June 30, 2014 Income tax provision (benefit) computed at the statutory federal rate $ 11,638,588 $ 2,868,267 $ 1,866,366 Reconciling items: Depletion in excess of basis (2,242,620 ) — — State income taxes, net of federal tax benefit 196,415 595,708 189,081 Permanent differences related to stock-based compensation — — (155,817 ) Other permanent differences (21,604 ) (19,754 ) (7,632 ) Income tax provision $ 9,570,779 $ 3,444,221 $ 1,891,998 |
Schedule of components of deferred taxes | The above assets and liabilities are present on the balance sheet as follows: June 30, 2016 June 30, 2015 June 30, 2014 Current deferred tax asset $ 105,321 $ 82,414 $ 159,624 Non-current deferred tax liability 11,840,693 11,242,551 9,897,272 Net liability 11,735,372 11,160,137 9,737,648 Asset (Liability) June 30, 2016 June 30, 2015 June 30, 2014 Deferred tax assets: Non-qualified stock-based compensation $ 553,182 $ 173,647 $ 134,469 Net operating loss carry-forwards 386,808 400,288 427,249 AMT credit carry-forward* — 701,254 701,254 Other 130,947 91,113 165,775 Gross deferred tax assets 1,070,937 1,366,302 1,428,747 Valuation allowance (292,446 ) (292,446 ) (292,446 ) Total deferred tax assets 778,491 1,073,856 1,136,301 Deferred tax liability: Oil and natural gas properties (12,513,863 ) (12,233,993 ) (10,873,949 ) Total deferred tax liability (12,513,863 ) (12,233,993 ) (10,873,949 ) Net deferred tax liability $ (11,735,372 ) $ (11,160,137 ) $ (9,737,648 ) _______________________________________________________________________________ * In fiscal 2016 we used our total AMT credit carry-forward of $901,545 . Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation. |
Net Income Per Share (Tables)
Net Income Per Share (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Earnings Per Share [Abstract] | |
Schedule of computation of basic and diluted income (loss) per share | The following table sets forth the computation of basic and diluted net income per share: June 30, 2016 2015 2014 Numerator Net income attributable to common shareholders $ 23,986,060 $ 4,317,555 $ 2,923,011 Denominator Weighted average number of common shares – Basic 32,810,375 32,817,456 30,895,832 Effect of dilutive securities: Contingent restricted stock grants 9,378 4,422 — Stock Options 41,478 102,140 1,668,235 Total weighted average dilutive securities 50,856 106,562 1,668,235 Weighted average number of common shares and dilutive potential common shares used in diluted EPS 32,861,231 32,924,018 32,564,067 Net income per common share – Basic $ 0.73 $ 0.13 $ 0.09 Net income per common share – Diluted $ 0.73 $ 0.13 $ 0.09 |
Schedule of outstanding potentially dilutive securities | The following were reflected in the calculation of diluted earnings per share as of June 30, 2016 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 91,172 Stock Options 2.19 35,231 Total $ 0.61 126,403 The following were reflected in the calculation of diluted earnings per share as of June 30, 2015 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Contingent Restricted Stock grants $ — 56,286 Stock Options $ 2.50 91,061 Total $ 1.55 147,347 The following were reflected in the calculation of diluted earnings per share as of June 30, 2014 : Outstanding Potential Dilutive Securities Weighted Average Exercise Price Outstanding at Stock Options $ 2.08 178,061 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of future minimum lease commitments under the operating lease | Future minimum lease commitments as of June 30, 2016 under these operating leases are as follows: For the fiscal year ended June 30, 2017 $ 80,235 2018 73,073 2019 66,984 Total $ 220,292 |
Concentrations of Credit Risk (
Concentrations of Credit Risk (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Risks and Uncertainties [Abstract] | |
Schedule of customers from whom the entity derived 10 percent or more of net oil and natural gas revenues | Year Ended June 30, Customer 2016 2015 2014 Plains Marketing L.P. (includes Delhi production) 99 % 99 % 96 % Enterprise Crude Oil LLC — % — % 2 % Flint Hills — % — % 1 % ETC Texas Pipeline, LTD. — % — % 1 % All others 1 % 1 % — % Total 100 % 100 % 100 % |
Derivatives (Tables)
Derivatives (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of crude oil derivative positions | The following sets forth a summary of the Company’s crude oil derivative positions at average NYMEX WTI prices as of June 30, 2016 . Period Type of Contract Volumes (in Bbls./day) Weighted Average Floor Price per Bbl. Weighted Average Ceiling Price per Bbl. Weighted Average Collar Spread per Bbl. Months of July 2016 through September 2016 Costless Collar 600 $45.00 $55.00 $10.00 |
Fair Value Measurement (Tables)
Fair Value Measurement (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Fair Value Disclosures [Abstract] | |
Schedule of assets and liabilities measured on a recurring basis | The following table summarize the location and amounts of the Company’s assets and liabilities measured at fair value on a recurring basis as presented in the consolidated balance sheets as of June 30, 2016 . All items included in the tables below are Level 2 inputs within the fair value hierarchy: June 30, 2016 Asset (Liability) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheets Current derivative assets $ 45,263 $ (31,131 ) $ 14,132 Current derivative liabilities (31,131 ) 31,131 — Total $ 14,132 $ — $ 14,132 |
Supplemental Disclosures abou48
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities | The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $140,151 , $576,039 and $66,976 during the years ended June 30, 2016 , 2015 , and 2014 , respectively. For the Years Ended June 30, 2016 2015 2014 Oil and Natural Gas Activities Property acquisition costs: Proved property $ — $ — $ — Unproved property (a) 596,500 — 47,344 Exploration costs — — 757,423 Development costs 19,093,200 10,975,637 18,566 Total costs incurred for oil and natural gas activities $ 19,689,700 $ 10,975,637 $ 823,333 |
Schedule of estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows: Crude Oil (Bbls) Natural Gas Liquids (Bbls) Natural Gas (Mcf) BOE Proved developed and undeveloped reserves: June 30, 2013 12,782,755 979,885 22,797 13,766,440 Revisions of previous estimates (a) (1,919,052 ) 1,269,588 2,412,677 (247,350 ) Improved recovery, extensions and discoveries 17,146 32,731 498,044 132,884 Sales of minerals in place (184,722 ) — — (184,722 ) Production (sales volumes) (169,783 ) (3,516 ) (26,655 ) (177,742 ) June 30, 2014 10,526,344 2,278,688 2,906,863 13,289,510 Revisions of previous estimates (b) (64,074 ) 156,195 (2,894,703 ) (390,330 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (450,294 ) (1,288 ) (7,221 ) (452,786 ) June 30, 2015 10,011,976 2,433,595 4,939 12,446,394 Revisions of previous estimates (c) (765,385 ) (198,233 ) (3,319 ) (964,171 ) Improved recovery, extensions and discoveries — — — — Sales of minerals in place — — — — Production (sales volumes) (658,041 ) (491 ) (1,620 ) (658,802 ) June 30, 2016 8,588,550 2,234,871 — 10,823,421 Proved developed reserves: June 30, 2013 10,077,522 8,539 22,797 10,089,861 June 30, 2014 7,858,224 32,164 481,042 7,970,562 June 30, 2015 7,347,231 1,572 4,939 7,349,626 June 30, 2016 7,168,249 — — 7,168,249 Proved undeveloped reserves: June 30, 2013 2,705,233 971,346 — 3,676,579 June 30, 2014 2,668,120 2,246,524 2,425,821 5,318,948 June 30, 2015 2,664,745 2,432,023 — 5,096,768 June 30, 2016 1,420,301 2,234,871 — 3,655,172 (a) Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO 2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes. (b) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well. (c) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period. |
Schedule of standardized measure of discounted future net cash flows related to proved oil and natural gas reserves | The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2016 , 2015 , and 2014 are as follows: For the Years Ended June 30, 2016 2015 2014 Future cash inflows $ 383,491,193 $ 807,030,282 $ 1,193,515,075 Future production costs and severance taxes (179,182,565 ) (309,225,333 ) (475,387,931 ) Future development costs (16,595,047 ) (49,691,006 ) (46,154,178 ) Future income tax expenses (45,713,438 ) (123,888,665 ) (195,581,510 ) Future net cash flows 142,000,143 324,225,278 476,391,456 10% annual discount for estimated timing of cash flows (64,042,824 ) (165,028,739 ) (250,313,784 ) Standardized measure of discounted future net cash flows $ 77,957,319 $ 159,196,539 $ 226,077,672 |
Schedule of NYMEX prices used in determining future cash flows | Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials. Year Ended June 30, 2016 2015 2014 Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) Oil (Bbl) Gas (MMBtu) NYMEX prices used in determining future cash flows $ 42.91 n/a $ 71.88 $ 3.44 $ 100.37 $ 4.10 |
Schedule of changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves | A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows: For the Years Ended June 30, 2016 2015 2014 Balance, beginning of year $ 159,196,539 $ 226,077,672 $ 307,220,699 Net changes in sales prices and production costs related to future production (120,832,747 ) (88,043,095 ) (73,439,526 ) Changes in estimated future development costs 74,991 (9,585,405 ) 9,848,614 Sales of oil and gas produced during the period, net of production costs (17,079,363 ) (18,538,016 ) (16,479,934 ) Net change due to extensions, discoveries, and improved recovery — — 775,574 Net change due to revisions in quantity estimates (18,821,014 ) (9,391,321 ) (23,757,788 ) Net change due to sales of minerals in place — — (3,150,277 ) Development costs incurred during the period 16,327,883 7,785,095 — Accretion of discount 21,870,650 31,974,540 45,896,187 Net change in discounted income taxes 36,598,239 34,157,767 58,073,450 Net changes in timing of production and other (a) 622,141 (15,240,698 ) (78,909,327 ) Balance, end of year $ 77,957,319 $ 159,196,539 $ 226,077,672 (a) Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014. |
Selected Quarterly Financial 49
Selected Quarterly Financial Data (Unaudited) (Tables) | 12 Months Ended |
Jun. 30, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Summary of quarterly financial information | The following table presents summarized quarterly financial information for the years ended June 30, 2016 and 2015 : 2016 First Second (1) Third Fourth (2) Revenues $ 7,379,406 $ 6,622,927 $ 5,106,735 $ 7,240,434 Operating income (loss) 1,846,498 (454,987 ) (681,147 ) 954,823 Net income (loss) available to common shareholders $ 2,923,652 $ 654,697 $ (298,183 ) $ 20,705,894 Basic net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 Diluted net income (loss) per share $ 0.09 $ 0.02 $ (0.01 ) $ 0.63 2015 First Second (3) Third Fourth Revenues $ 4,004,827 $ 7,708,067 $ 7,064,689 $ 9,063,682 Operating income 1,840,866 2,162,294 1,245,990 3,334,547 Net income available to common shareholders $ 960,435 $ 1,071,342 $ 566,011 $ 1,719,767 Basic net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 Diluted net income per share $ 0.03 $ 0.03 $ 0.02 $ 0.05 (1) Includes $1.3 million restructuring charge. (2) Includes gain on settlement of Delhi field litigation of $28.1 million . (3) Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field. |
Summary of Significant Accoun50
Summary of Significant Accounting Policies (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Jun. 30, 2015 | |
Accounting Policies [Abstract] | ||
Allowance for doubtful accounts | $ 0 | $ 0 |
Oil and natural gas properties | ||
Limitation on Capitalized Costs | ||
Discount rate for present value (as a percent) | 10.00% | |
Period considered for computing unweighted arithmetic average of oil and natural gas prices (in months) | 12 months | |
Other Property and Equipment | Minimum | ||
Other Property and Equipment | ||
Expected lives of the individual assets or group of assets | 3 years | |
Other Property and Equipment | Maximum | ||
Other Property and Equipment | ||
Expected lives of the individual assets or group of assets | 7 years |
Dehli Field Litigation Settle51
Dehli Field Litigation Settlement (Details) - USD ($) | Jul. 01, 2016 | Jun. 24, 2016 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Loss Contingencies [Line Items] | |||||
Delhi field litigation settlement gain | $ 28,096,500 | $ 0 | $ 0 | ||
Fair value of litigation settlement | 596,500 | $ 0 | $ 0 | ||
Dehli Field Litigation | |||||
Loss Contingencies [Line Items] | |||||
Delhi field litigation settlement gain | $ 28,100,000 | ||||
Dehli Field Litigation | Denbury Resources, Inc | |||||
Loss Contingencies [Line Items] | |||||
Delhi field litigation settlement gain | $ 28,100,000 | ||||
Proceeds from litigation | $ 27,500,000 | ||||
Working interest in Mengal Sand Interval | 23.90% | ||||
Fair value of litigation settlement | $ 596,500 | ||||
Dehli Field Litigation | Denbury Resources, Inc | Subsequent Event | |||||
Loss Contingencies [Line Items] | |||||
Overriding royalty interest in Holt-Bryant | 0.2226% | ||||
Dehli Field Litigation | Denbury Resources, Inc | Level 2 | |||||
Loss Contingencies [Line Items] | |||||
Fair value of litigation settlement | $ 596,500 |
Receivables (Details)
Receivables (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Receivables [Abstract] | ||
Receivables from oil and gas sales | $ 2,637,593 | $ 3,122,155 |
Other | 595 | 318 |
Total receivables | $ 2,638,188 | $ 3,122,473 |
Prepaid Expenses and Other Cu53
Prepaid Expenses and Other Current Assets (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | |||
Prepaid insurance | $ 168,681 | $ 178,994 | |
Prepaid federal and state income taxes | 0 | 22,542 | |
Equipment inventory | [1] | 0 | 81,538 |
Retainers and deposits | 30,568 | 26,978 | |
Other prepaid expenses | 52,500 | 59,352 | |
Prepaid expenses and other current assets | $ 251,749 | $ 369,404 | |
[1] | As discussed in Note 8, our equipment inventory was determined to have no future value in use for our operations and negligible market value and was charged to restructuring costs as part of the separation of our artificial lift technology operations. |
Property and Equipment - Summar
Property and Equipment - Summary of Property and Equipment (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Oil and natural gas properties: | ||
Property costs subject to amortization | $ 77,408,353 | $ 57,718,653 |
Less: Accumulated depreciation, depletion, and amortization | (17,437,890) | (12,531,767) |
Unproved properties not subject to amortization | 0 | 0 |
Oil and natural gas properties, net | 59,970,463 | 45,186,886 |
Other property and equipment: | ||
Furniture, fixtures and office equipment, at cost | 228,752 | 287,680 |
Artificial lift technology equipment, at cost | 7,000 | 319,994 |
Less: Accumulated depreciation | (207,103) | (330,918) |
Other property and equipment, net | $ 28,649 | $ 276,756 |
Property and Equipment - Narrat
Property and Equipment - Narrative (Details) - USD ($) | Jun. 24, 2016 | Oct. 24, 2014 | Dec. 01, 2013 | Nov. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Property, Plant and Equipment [Line Items] | |||||||
Fair value of litigation settlement | $ 596,500 | $ 0 | $ 0 | ||||
Capital costs charged to expense | $ 5,165,120 | 3,615,737 | 1,228,685 | ||||
Percentage of net profits from production | 25.00% | ||||||
Installation costs of artificial lift technology | 217,733 | 377,943 | |||||
Additional depreciation | 275,682 | ||||||
Proceeds from asset sales | $ 0 | $ 398,242 | $ 542,347 | ||||
Denbury Resources, Inc | Dehli Field Litigation | |||||||
Property, Plant and Equipment [Line Items] | |||||||
Working interest in Mengal Sand Interval | 23.90% | ||||||
Fair value of litigation settlement | $ 596,500 | ||||||
Artificial lift equipment | |||||||
Property, Plant and Equipment [Line Items] | |||||||
Capital costs charged to expense | $ 210,392 | ||||||
Oil and natural gas properties | |||||||
Property, Plant and Equipment [Line Items] | |||||||
Proceeds from asset sales | $ 389,165 | $ 402,500 | |||||
Delhi Field | |||||||
Property, Plant and Equipment [Line Items] | |||||||
Capital expenditures | 19,000,000 | ||||||
NGL Plant Project | |||||||
Property, Plant and Equipment [Line Items] | |||||||
Capital expenditures | 16,400,000 | ||||||
Incurred costs on a cumulative basis | 21,500,000 | ||||||
Total authorized commitment | 24,600,000 | ||||||
Remaining balance of authorized commitment | $ 3,100,000 |
Other Assets (Details)
Other Assets (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract] | ||
Royalty rights | $ 108,512 | $ 0 |
Less: Accumulated amortization of royalty rights | (6,782) | 0 |
Investment in Well Lift Inc., at cost | 108,750 | 0 |
Deferred loan costs | 168,972 | 337,078 |
Less: Accumulated amortization of deferred loan costs | (13,963) | (147,057) |
Trademarks | 0 | 44,803 |
Patent costs | 0 | 538,276 |
Less: Accumulated amortization of patent costs | 0 | (47,063) |
Other assets, net | $ 365,489 | $ 726,037 |
Other Assets - Additional Infor
Other Assets - Additional Information (Details) - USD ($) | 12 Months Ended | |
Jun. 30, 2016 | Apr. 30, 2016 | |
Line of Credit Facility [Line Items] | ||
Unamortized debt issuance costs | $ 155,009 | |
Revolving Credit Facility | Texas Capital Bank, N.A. | ||
Line of Credit Facility [Line Items] | ||
Unamortized debt issuance costs | $ 179,468 | |
Revolving Credit Facility | Delhi Field | Texas Capital Bank, N.A. | ||
Line of Credit Facility [Line Items] | ||
Deferred legal fees | 50,414 | |
Costs incurred for title work related to the Dehli Field | 107,196 | |
Line of Credit | Senior Secured Reserve-Based Credit Facility | ||
Line of Credit Facility [Line Items] | ||
Unamortized debt issuance costs | $ 168,972 | |
Debt issuance costs amortized | $ 46,374 |
Restructuring - Investments in
Restructuring - Investments in Well Lift Inc (Details) | 1 Months Ended | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Dec. 31, 2015USD ($) | Dec. 31, 2015USD ($) | Jun. 30, 2015USD ($)employee | Dec. 31, 2015USD ($) | Jun. 30, 2016USD ($) | Jun. 30, 2015USD ($) | Jun. 30, 2014USD ($) | Nov. 01, 2013USD ($) | |
Schedule of Cost-method Investments [Line Items] | ||||||||
Investment in Well Lift Inc., at cost | $ 0 | $ 108,750 | $ 0 | |||||
Restructuring charges | $ 1,300,000 | 1,257,433 | (5,431) | $ 1,293,186 | ||||
Stock-based compensation | 1,750,209 | $ 943,653 | $ 1,352,322 | |||||
Restructuring Reserve | $ 1,332,186 | |||||||
GARP | ||||||||
Schedule of Cost-method Investments [Line Items] | ||||||||
Number of employees terminated | employee | 3 | |||||||
Restructuring charges | $ 688,205 | |||||||
Restructuring Reserve | $ 628,866 | 628,866 | 628,866 | $ 419,488 | ||||
GARP | Restructuring Charges | ||||||||
Schedule of Cost-method Investments [Line Items] | ||||||||
Stock-based compensation | 59,339 | |||||||
Well Lift Inc. | ||||||||
Schedule of Cost-method Investments [Line Items] | ||||||||
Investment in Well Lift Inc., at cost | $ 108,750 | $ 108,750 | $ 108,750 | |||||
Ownership percentage | 17.50% | 17.50% | 17.50% | |||||
Ownership percentage after conversion of preferred stock into common stock | 42.50% | 42.50% | 42.50% | |||||
Perpetual royalty percentage | 5.00% | |||||||
Discounted net present value of assets | $ 108,512 | $ 108,512 | $ 108,512 | |||||
Well Lift Inc. | GARP | Exchange of Assets | ||||||||
Schedule of Cost-method Investments [Line Items] | ||||||||
Amortization expense | 469,395 | |||||||
Inventory write down to production costs | 92,901 | |||||||
Depreciation expense | 6,932 | |||||||
Total impairments | $ 569,228 |
Restructuring - Schedule of Res
Restructuring - Schedule of Restructuring and Related Costs (Details) - USD ($) | 6 Months Ended | 18 Months Ended |
Jun. 30, 2016 | Jun. 30, 2015 | |
Salary expense | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | $ 615,721 | |
Payments | (615,721) | |
Adjustment to Cost | 0 | |
Ending balance | 0 | |
Incentive compensation costs | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | 185,525 | |
Payments | (185,525) | |
Adjustment to Cost | 0 | |
Ending balance | 0 | |
Payroll taxes and benefits expense | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | 154,575 | |
Payments | (110,144) | |
Adjustment to Cost | (44,431) | |
Ending balance | 0 | |
Accrued liability for restructuring costs | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | 955,821 | |
Payments | (911,390) | |
Adjustment to Cost | (44,431) | |
Ending balance | $ 0 | |
GARP | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | $ 628,866 | |
Payments | (209,378) | |
Adjustment to Cost | 0 | |
Ending balance | 419,488 | |
GARP | Salary expense | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | 530,387 | |
Payments | (176,796) | |
Adjustment to Cost | 0 | |
Ending balance | 353,591 | |
GARP | Payroll taxes and benefits expense | ||
Restructuring Reserve [Roll Forward] | ||
Beginning balance | 98,479 | |
Payments | (32,582) | |
Adjustment to Cost | 0 | |
Ending balance | $ 65,897 |
Restructuring - Narrative (Deta
Restructuring - Narrative (Details) - USD ($) | 12 Months Ended | |||||
Jun. 30, 2016 | Dec. 31, 2014 | Jun. 30, 2014 | Jun. 30, 2015 | Dec. 31, 2013 | Nov. 01, 2013 | |
Restructuring Cost and Reserve [Line Items] | ||||||
Restructuring Reserve | $ 1,332,186 | |||||
Accrued liability for restructuring costs | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Restructuring Reserve | $ 955,821 | $ 0 | $ 955,821 | |||
Restructuring Charges | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Non-cash stock-based compensation expense | $ 0 | $ 376,365 | ||||
Restructuring Charges | Stock Compensation, Restructuring | ||||||
Restructuring Cost and Reserve [Line Items] | ||||||
Non-cash stock-based compensation expense | $ 376,365 |
Accrued Liabilities and Other -
Accrued Liabilities and Other - Schedule of Other Current Liabilities (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 |
Other Liabilities Disclosure [Abstract] | ||
Accrued incentive and other compensation | $ 999,172 | $ 578,910 |
Accrued restructuring charges | 419,488 | 0 |
Asset retirement obligations due within one year | 201,896 | 57,223 |
Accrued royalties, including suspended accounts | 49,580 | 75,164 |
Accrued franchise taxes | 62,834 | 94,885 |
Payable for settled derivatives | 318,708 | 0 |
Accrued - other | 46,273 | 49,191 |
Accrued liabilities and other | $ 2,097,951 | $ 855,373 |
Asset Retirement Obligations -
Asset Retirement Obligations - Summary of Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Reconciliation of the beginning and ending asset retirement obligation | ||||
Asset retirement obligations—beginning of period | $ 772,990 | $ 352,215 | ||
Liabilities incurred | [1] | 28,505 | 564,019 | |
Liabilities settled | 0 | (137,604) | ||
Liabilities sold | 0 | (52,526) | ||
Accretion of discount | 49,054 | 34,866 | $ 41,626 | |
Revisions to previous estimates | 111,647 | 12,020 | ||
Asset retirement obligations—ending of period | 962,196 | 772,990 | $ 352,215 | |
Less: current asset retirement obligations | (201,896) | (57,223) | ||
Long-term portion of asset retirement obligations | $ 760,300 | $ 715,767 | ||
[1] | Liabilities incurred during fiscal 2015 relate to our share of the estimated abandonment costs of the wells and facilities in the Delhi field subsequent to the reversion of our working interest. |
Stockholders' Equity - Narrativ
Stockholders' Equity - Narrative (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||
Jun. 30, 2015 | Dec. 31, 2013 | Mar. 31, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | May 12, 2015 | |
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Common shares issued during period for share based compensation (shares) | 1,568,832 | ||||||
Proceeds from the exercise of stock options | $ 51,000 | $ 141,600 | $ 3,252,801 | ||||
Stock issued, nonqualified stock options and incentive warrants noncash (shares) | 2,635,696 | ||||||
Shares received in lieu of cash payment (shares) | 50,956 | ||||||
Shares received in lieu of cash payment, average cost of shares (in USD per share) | $ 12.14 | ||||||
Treasury stock retired (shares) | 801,889 | ||||||
Treasury stock retired, value | $ 1,019,840 | ||||||
Purchases of treasury stock (shares) | 186,714 | ||||||
Treasury stock acquired, average cost (in USD per share) | $ 12.18 | ||||||
Purchases of treasury stock | 1,263,402 | 504,124 | $ 2,273,857 | ||||
Cash dividends paid (per common share) | $ 0.10 | $ 0.05 | |||||
Dividends paid | 6,565,823 | 9,833,642 | 9,723,833 | ||||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Cash dividends to preferred stockholders | $ 674,302 | $ 674,302 | 674,302 | ||||
Series A Cumulative Preferred Stock | |||||||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Issuance of preferred stock (in shares) | 317,319 | ||||||
Preferred stock dividend rate (as a percent) | 8.50% | 8.50% | |||||
Amount of sinking fund available to stockholders | $ 0 | ||||||
Preferred stock, liquidation preference (in dollars per share) | $ 25 | $ 25 | $ 25 | ||||
Dividend payable monthly on preferred stock (in dollars per share) | $ 0.177083 | ||||||
Cash dividends to preferred stockholders | $ 674,302 | $ 674,302 | $ 674,302 | ||||
Common Stock | |||||||
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Purchases of treasury stock (shares) | 218,682 | 70,907 | 186,714 | ||||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Percentage of cash dividends treated as qualified dividend income | 14.00% | ||||||
Percentage of cash dividends treated as return of capital | 86.00% | ||||||
Preferred | |||||||
Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Percentage of cash dividends treated as qualified dividend income | 100.00% | ||||||
2015 Share Repurchase Program | Common Stock | |||||||
Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract] | |||||||
Purchases of treasury stock (shares) | 265,762 | 202,390 | |||||
Treasury stock acquired, average cost (in USD per share) | $ 6.05 | $ 5.80 | |||||
Purchases of treasury stock | $ 1,609,008 | $ 1,173,899 | |||||
Amount authorized to be repurchased | $ 5,000,000 |
Stock-Based Incentive Plan - Na
Stock-Based Incentive Plan - Narrative (Details) - USD ($) | Aug. 27, 2014 | Feb. 29, 2016 | Dec. 31, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Exercise of stock options (shares) | 50,000 | 87,000 | ||||
Stock options intrinsic value | $ 131,000 | $ 501,810 | ||||
Option vested (in shares) | 35,231 | |||||
Restructuring Charges | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Non-cash stock-based compensation expense | $ 0 | $ 376,365 | ||||
Stock Options | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Option vested (in shares) | 0 | 0 | 0 | |||
Stock Options and Incentive Warrants | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Exercise of stock options (shares) | 4,644,759 | |||||
Stock options intrinsic value | $ 47,504,114 | |||||
Contingent Restricted Stock Grants | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares forfeited (shares) | 14,212 | 29,866 | ||||
Restricted Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares forfeited (shares) | 31,467 | 62,774 | ||||
Restricted stock, vested (shares) | 86,719 | 91,306 | 277,198 | |||
Restricted stock, vested in period, grant date fair value (in dollars per share) | $ 757,229 | $ 766,970 | $ 1,796,243 | |||
Non-cash stock-based compensation expense | $ 1,809,548 | $ 943,653 | $ 1,728,687 | |||
Restricted Stock, Market Based | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period (in years) | 3 years 303 days | |||||
Fair value at grant date, per share (in dollars per share) | $ 4.58 | |||||
Shares granted (in shares) | 64,752 | |||||
Restricted Stock, Market Based | Minimum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period (in years) | 3 years 109 days | |||||
Fair value at grant date, per share (in dollars per share) | $ 2.93 | $ 4.26 | ||||
Restricted Stock, Market Based | Maximum | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period (in years) | 2 years 200 days | |||||
Fair value at grant date, per share (in dollars per share) | 5.07 | $ 8.40 | ||||
Restricted Stock, Performance Based | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Fair value at grant date, per share (in dollars per share) | $ 6.09 | |||||
Shares granted (in shares) | 64,752 | |||||
Restricted Stock, Performance Based | Various Employees | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares voluntarily relinquished (in shares) | 31,307 | |||||
Restricted Stock, Service Based | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Fair value at grant date, per share (in dollars per share) | $ 5.84 | |||||
Shares granted (in shares) | 164,610 | |||||
Restricted Stock, Service Based | Various Employees | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares granted (in shares) | 22,016 | |||||
Contingent Performance-based Shares | Various Employees | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Number of shares voluntarily relinquished (in shares) | 15,654 | |||||
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Shares authorized for granting (shares) | 6,500,000 | |||||
Shares available for grant (shares) | 282,133 | |||||
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | Restricted Stock and Contingent Restricted Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Expiration period (in years) | 4 years | |||||
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | Restricted Stock | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period (in years) | 4 years | |||||
Evolution Petroleum Corporation Amended and Restated 2004 Stock Plan | Performance Shares | ||||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||||
Vesting period (in years) | 4 years |
Stock-Based Incentive Plan - Sc
Stock-Based Incentive Plan - Schedule of Options and Incentive Warrants (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | ||
Number of Stock Options | |||
Stock Options Outstanding, Beginning of Period (in shares) | 91,061 | ||
Stock Options , Exercises (in shares) | (50,000) | (87,000) | |
Stock Options, Expirations (in shares) | (5,830) | ||
Stock Options Outstanding, End of Period (in shares) | 35,231 | 91,061 | |
Stock Options, Vested and Expected to Vest (in shares) | 35,231 | ||
Stock Options, Exercisable (in shares) | 35,231 | ||
Weighted Average Exercise Price | |||
Stock Options Outstanding, Weighted Average Exercise Price, Beginning of Period (in USD per share) | $ 2.50 | ||
Stock Options, Exercises, Weighted Average Exercise Price (in USD per share) | 2.55 | ||
Stock Options, Expirations, Weighted Average Exercise Price (in USD per share) | 4.02 | ||
Stock Options, Weighted Average Exercise Price, End of Period (in USD per share) | 2.19 | $ 2.50 | |
Stock Options, Vested and Expected to Vest, Weighted Average Exercise Price (in USD per share) | 2.19 | ||
Stock Options, Exercisable, Weighted Average Exercise Price (in USD per share) | $ 2.19 | ||
Aggregate Intrinsic Value | |||
Stock Options, Outstanding, Aggregate Intrinsic Value | [1] | $ 115,558 | |
Stock Options, Vested and Expected to Vest, Aggregate Intrinsic Value | [1] | 115,558 | |
Stock Options, Exercisable, Aggregate Intrinsic Value | [1] | $ 115,558 | |
Stock Options, Outstanding, Weighted Average Remaining Contractual Term (in years) | 1 year 2 months 12 days | ||
Stock Options, Vested and Expected to Vest, Weighted Average Remaining Contractual Term (in years) | 1 year 2 months 12 days | ||
Stock Options, Exercisable, Weighted Average Remaining Contractual Term (in years) | 1 year 2 months 12 days | ||
Common Stock | |||
Aggregate Intrinsic Value | |||
Share price (in dollars per share) | $ 5.47 | ||
[1] | Based upon the difference between the market price of our common stock on the last trading date of the period ($5.47 as of June 30, 2016) and the Stock Option exercise price of in-the-money Stock Options. |
Stock-Based Incentive Plan - 66
Stock-Based Incentive Plan - Schedule of Restricted Stock (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Dec. 31, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Restricted Stock | ||||
Number of Restricted Shares | ||||
Nonvested, beginning of period (shares) | 262,227 | |||
Vested (shares) | (86,719) | (91,306) | (277,198) | |
Forfeited (shares) | (31,467) | (62,774) | ||
Nonvested, end of period (shares) | 406,848 | 262,227 | ||
Weighted Average Grant-Date Fair Value | ||||
Weighted average grant date fair value, beginning of period (in USD per share) | $ 9.37 | |||
Vested, weighted average grant date fair value (in USD per share) | 8.73 | |||
Forfeited, weighted average grant date fair value (in USD per share) | 9.72 | |||
Weighted average grant date fair value, end of period (in USD per share) | $ 6.74 | $ 9.37 | ||
Unamortized compensation expense | $ 1,536,125 | $ 0 | ||
Weighted Average Remaining Amortization Period (in years) | 2 years 7 months 6 days | |||
Restricted Stock, Service Based | ||||
Number of Restricted Shares | ||||
Grants (shares) | 164,610 | |||
Nonvested, end of period (shares) | 224,515 | |||
Weighted Average Grant-Date Fair Value | ||||
Grants, weighted average grant date fair value (in USD per share) | $ 5.84 | |||
Weighted average grant date fair value, end of period (in USD per share) | $ 7.08 | |||
Restricted Stock, Performance Based | ||||
Number of Restricted Shares | ||||
Grants (shares) | 64,752 | |||
Nonvested, end of period (shares) | 89,079 | |||
Weighted Average Grant-Date Fair Value | ||||
Grants, weighted average grant date fair value (in USD per share) | $ 6.09 | |||
Weighted average grant date fair value, end of period (in USD per share) | $ 7.17 | |||
Restricted Stock, Market Based | ||||
Number of Restricted Shares | ||||
Grants (shares) | 64,752 | |||
Nonvested, end of period (shares) | 93,254 | |||
Weighted Average Grant-Date Fair Value | ||||
Grants, weighted average grant date fair value (in USD per share) | $ 4.58 | |||
Weighted average grant date fair value, end of period (in USD per share) | $ 5.50 |
Stock-Based Incentive Plan - 67
Stock-Based Incentive Plan - Schedule of Contingent Restricted Stock (Details) - USD ($) | 1 Months Ended | 12 Months Ended | |
Dec. 31, 2015 | Jun. 30, 2016 | ||
Contingent Restricted Stock Grants | |||
Number of Restricted Stock Units | |||
Nonvested, beginning of period (shares) | 56,286 | ||
Forfeited (shares) | (14,212) | (29,866) | |
Nonvested, end of period (shares) | 91,172 | ||
Weighted Average Grant-Date Fair Value | |||
Weighted average grant date fair value, beginning of period (in USD per share) | $ 8.20 | ||
Forfeited, weighted average grant date fair value (in USD per share) | 9.33 | ||
Weighted average grant date fair value, end of period (in USD per share) | $ 5.21 | ||
Unamortized compensation expense | [1] | $ 107,219 | |
Weighted Average Remaining Amortization Period (in years) | 2 years 9 months 18 days | ||
Contingent Restricted Stock, Performance Based | |||
Number of Restricted Stock Units | |||
Grants (shares) | 32,376 | ||
Nonvested, end of period (shares) | 44,542 | ||
Weighted Average Grant-Date Fair Value | |||
Grants, weighted average grant date fair value (in USD per share) | $ 6.09 | ||
Weighted average grant date fair value, end of period (in USD per share) | $ 7.17 | ||
Potential future compensation expense | $ 122,268 | ||
Contingent Restricted Stock, Market Based | |||
Number of Restricted Stock Units | |||
Grants (shares) | 32,376 | ||
Nonvested, end of period (shares) | 46,630 | ||
Weighted Average Grant-Date Fair Value | |||
Grants, weighted average grant date fair value (in USD per share) | $ 2.93 | ||
Weighted average grant date fair value, end of period (in USD per share) | $ 3.34 | ||
[1] | Excludes $122,268 of potential future compensation expense for performance-based awards for which vesting is not considered probable at this time for accounting purposes. |
Supplemental Disclosure of Ca68
Supplemental Disclosure of Cash Flow Information - Schedule of Supplement Cash Flow (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Supplemental Cash Flow Elements [Abstract] | |||
Income taxes paid | $ 540,000 | $ 220,000 | $ 755,941 |
Income tax refunds | 1,556,999 | 331,733 | 0 |
Non-cash transactions: | |||
Increase (decrease) in accrued purchases of property and equipment | (2,250,048) | 5,422,566 | (183,766) |
Deferred loan costs charged to oil and gas property costs | 107,196 | 0 | 0 |
Oil and natural gas property costs attributable to the recognition of asset retirement obligations | 140,151 | 576,039 | 66,976 |
Mengel working interest acquired in Delhi Field litigation settlement | 596,500 | 0 | 0 |
Royalty rights acquired through non-monetary exchange of patent and trademark assets | 108,512 | 0 | 0 |
Previously acquired Company shares swapped by holders to pay stock option exercise price | 76,500 | 0 | 618,606 |
Accrued purchases of treasury stock | $ (170,283) | $ 170,283 | $ 0 |
Income Taxes - Narrative (Detai
Income Taxes - Narrative (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Sep. 30, 2015 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Operating Loss Carryforwards [Line Items] | ||||
Unrecognized tax benefits | $ 0 | $ 0 | $ 0 | |
Statutory tax rate | 34.00% | |||
Tax loss carryforwards from exercise of options and warrants | $ 25,300,000 | |||
Tax benefits related to stock-based compensation | 9,650,657 | $ 1,633,946 | $ 509,096 | |
Net loss for state tax purposes | $ 19,100,000 | |||
Mineral Property Depletion | ||||
Operating Loss Carryforwards [Line Items] | ||||
Depletion carryforward | 5,000,000 | |||
Federal | ||||
Operating Loss Carryforwards [Line Items] | ||||
Tax loss carryforward from reverse merger | 1,200,000 | |||
Carryforward from reverse merger | 300,000 | |||
Annual amount of carryforward from reverse merger through 2023 | $ 39,648 | |||
State | ||||
Operating Loss Carryforwards [Line Items] | ||||
Net loss for state tax purposes | 24,200,000 | |||
Louisiana | State | ||||
Operating Loss Carryforwards [Line Items] | ||||
Income tax refund | 1,500,000 | |||
Interest on refund recorded as a deduction of current income tax expense | $ 57,467 |
Income Taxes - Components of In
Income Taxes - Components of Income Tax Provision (Benefit) (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Current: | |||
Federal | $ 8,731,290 | $ 1,413,296 | $ 386,018 |
State | 264,254 | 608,436 | 161,168 |
Total current income tax provision | 8,995,544 | 2,021,732 | 547,186 |
Deferred: | |||
Federal | 541,891 | 1,282,059 | 1,319,727 |
State | 33,344 | 140,430 | 25,085 |
Total deferred income tax provision | 575,235 | 1,422,489 | 1,344,812 |
Total income tax provision | $ 9,570,779 | $ 3,444,221 | $ 1,891,998 |
Income Taxes - Reconciliation o
Income Taxes - Reconciliation of Statutory and Income Tax Expense (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Income Tax Disclosure [Abstract] | |||
Income tax provision (benefit) computed at the statutory federal rate | $ 11,638,588 | $ 2,868,267 | $ 1,866,366 |
Depletion in excess of basis | (2,242,620) | 0 | 0 |
State income taxes, net of federal tax benefit | 196,415 | 595,708 | 189,081 |
Permanent differences related to stock-based compensation | 0 | 0 | (155,817) |
Other permanent differences | (21,604) | (19,754) | (7,632) |
Total income tax provision | $ 9,570,779 | $ 3,444,221 | $ 1,891,998 |
Income Taxes - Schedule of Defe
Income Taxes - Schedule of Deferred Income Taxes (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Deferred tax assets: | ||||
Non-qualified stock-based compensation | $ 553,182 | $ 173,647 | $ 134,469 | |
Net operating loss carry-forwards | 386,808 | 400,288 | 427,249 | |
AMT credit carry-forward | [1] | 0 | 701,254 | 701,254 |
Other | 130,947 | 91,113 | 165,775 | |
Gross deferred tax assets | 1,070,937 | 1,366,302 | 1,428,747 | |
Valuation allowance | (292,446) | (292,446) | (292,446) | |
Total deferred tax assets | 778,491 | 1,073,856 | 1,136,301 | |
Deferred tax liability: | ||||
Oil and natural gas properties | (12,513,863) | (12,233,993) | (10,873,949) | |
Total deferred tax liability | (12,513,863) | (12,233,993) | (10,873,949) | |
Net deferred tax liability | (11,735,372) | $ (11,160,137) | $ (9,737,648) | |
AMT credit carry-forward | 901,545 | |||
AMT associated with stock-based compensation | $ 200,291 | |||
[1] | In fiscal 2016 we used our total AMT credit carry-forward of $901,545. Our previous deferred tax asset above did not include $200,291 of AMT credit carry-forward associated with the tax benefit related to stock-based compensation. |
Income Taxes - Balance Sheet It
Income Taxes - Balance Sheet Items (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 |
Income Tax Disclosure [Abstract] | |||
Current deferred tax asset | $ 105,321 | $ 82,414 | $ 159,624 |
Non-current deferred tax liability | 11,840,693 | 11,242,551 | 9,897,272 |
Net liability | $ 11,735,372 | $ 11,160,137 | $ 9,737,648 |
Related Party Transactions - Na
Related Party Transactions - Narrative (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Vice President | |||
Related Party Transaction [Line Items] | |||
Related party payments | $ 0 | $ 26,579 | $ 10,113 |
Net Income Per Share - Schedule
Net Income Per Share - Schedule of Basic and Diluted Earnings (Loss) Per Share (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||||||
Jun. 30, 2016 | [1] | Mar. 31, 2016 | Dec. 31, 2015 | [2] | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | [3] | Sep. 30, 2014 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Numerator | ||||||||||||||
Net income attributable to common shareholders | $ 20,705,894 | $ (298,183) | $ 654,697 | $ 2,923,652 | $ 1,719,767 | $ 566,011 | $ 1,071,342 | $ 960,435 | $ 23,986,060 | $ 4,317,555 | $ 2,923,011 | |||
Denominator | ||||||||||||||
Weighted average number of common shares—Basic (in shares) | 32,810,375 | 32,817,456 | 30,895,832 | |||||||||||
Effect of dilutive securities: | ||||||||||||||
Total weighted average dilutive securities (in shares) | 50,856 | 106,562 | 1,668,235 | |||||||||||
Weighted average number of common shares and dilutive potential common shares used in diluted EPS (in shares) | 32,861,231 | 32,924,018 | 32,564,067 | |||||||||||
Net income (loss) per common share - Basic (in dollars per share) | $ 0.63 | $ (0.01) | $ 0.02 | $ 0.09 | $ 0.05 | $ 0.02 | $ 0.03 | $ 0.03 | $ 0.73 | $ 0.13 | $ 0.09 | |||
Net income (loss) per common share - Diluted (in dollars per share) | $ 0.63 | $ (0.01) | $ 0.02 | $ 0.09 | $ 0.05 | $ 0.02 | $ 0.03 | $ 0.03 | $ 0.73 | $ 0.13 | $ 0.09 | |||
Contingent restricted stock grants | ||||||||||||||
Effect of dilutive securities: | ||||||||||||||
Weighted average dilutive securities (in shares) | 9,378 | 4,422 | 0 | |||||||||||
Stock Options | ||||||||||||||
Effect of dilutive securities: | ||||||||||||||
Weighted average dilutive securities (in shares) | 41,478 | 102,140 | 1,668,235 | |||||||||||
[1] | Includes gain on settlement of Delhi field litigation of $28.1 million. | |||||||||||||
[2] | Includes $1.3 million restructuring charge. | |||||||||||||
[3] | Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field. |
Net Income Per Share - Schedu76
Net Income Per Share - Schedule of Outstanding Potentially Dilutive Securities (Details) - $ / shares | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Weighted Average Exercise Price (in dollars per share) | $ 0.61 | $ 1.55 | |
Outstanding (in shares) | 126,403 | 147,347 | |
Contingent Restricted Stock grants | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Weighted Average Exercise Price (in dollars per share) | $ 0 | $ 0 | |
Outstanding (in shares) | 91,172 | 56,286 | |
Stock Options | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Weighted Average Exercise Price (in dollars per share) | $ 2.19 | $ 2.50 | $ 2.08 |
Outstanding (in shares) | 35,231 | 91,061 | 178,061 |
Credit Agreements (Details)
Credit Agreements (Details) | Apr. 11, 2016USD ($) | Feb. 29, 2012USD ($) | Jun. 30, 2016USD ($) | Apr. 30, 2016USD ($) | Jun. 30, 2015USD ($) |
Debt Instrument [Line Items] | |||||
Unamortized debt issuance costs | $ 155,009 | ||||
Texas Capital Bank, N.A. | Revolving Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Term of debt instrument | 4 years | ||||
Debt issuance costs | $ 179,468 | ||||
Unamortized debt issuance costs | $ 179,468 | ||||
Current borrowing base | $ 5,000,000 | ||||
Outstanding borrowings | $ 0 | ||||
Texas Capital Bank, N.A. | Letter of Credit | |||||
Debt Instrument [Line Items] | |||||
Outstanding borrowings | $ 0 | ||||
Line of Credit | Senior Secured Reserve-Based Credit Facility | Revolving Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Term of debt instrument | 3 years | ||||
Maximum borrowing capacity | $ 50,000,000 | ||||
Initial borrowing base | $ 10,000,000 | ||||
Placement fee percentage | 0.50% | ||||
Placement fee amount | $ 50,000 | ||||
Commitment fee percentage | 0.25% | ||||
Maximum total leverage ratio | 3 | ||||
Debt service coverage ratio | 1.10 | ||||
Minimum consolidated tangible net worth | $ 40,000,000 | ||||
Debt issuance costs | $ 168,972 | ||||
Line of Credit | Senior Secured Reserve-Based Credit Facility | LIBOR | Revolving Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 2.75% | ||||
Line of Credit | Senior Secured Reserve-Based Credit Facility | Prime Rate | Revolving Credit Facility | |||||
Debt Instrument [Line Items] | |||||
Basis spread on variable rate | 1.00% |
Commitments and Contingencies -
Commitments and Contingencies - Schedule of Future Minimum Lease Commitments (Details) | Jun. 30, 2016USD ($) |
Commitments and Contingencies Disclosure [Abstract] | |
2,017 | $ 80,235 |
2,018 | 73,073 |
2,019 | 66,984 |
Total | $ 220,292 |
Commitments and Contingencies79
Commitments and Contingencies - Narrative (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Term of operating lease (in years) | 3 years | ||
Rent expense | $ 182,626 | $ 175,103 | $ 174,229 |
Concentrations of Credit Risk -
Concentrations of Credit Risk - Schedule of Credit Risk (Details) - Net revenue - Major Customers | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Concentrations of Credit Risk | |||
Percent of Total Revenue | 100.00% | 100.00% | 100.00% |
Plains Marketing L.P. (includes Delhi production) | |||
Concentrations of Credit Risk | |||
Percent of Total Revenue | 99.00% | 99.00% | 96.00% |
Enterprise Crude Oil LLC | |||
Concentrations of Credit Risk | |||
Percent of Total Revenue | 0.00% | 0.00% | 2.00% |
Flint Hills | |||
Concentrations of Credit Risk | |||
Percent of Total Revenue | 0.00% | 0.00% | 1.00% |
ETC Texas Pipeline, LTD. | |||
Concentrations of Credit Risk | |||
Percent of Total Revenue | 0.00% | 0.00% | 1.00% |
All others | |||
Concentrations of Credit Risk | |||
Percent of Total Revenue | 1.00% | 1.00% | 0.00% |
Retirement Plan (Details)
Retirement Plan (Details) - USD ($) | 12 Months Ended | ||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |
Compensation and Retirement Disclosure [Abstract] | |||
Employer match of employee contributions of first 6% of eligible compensation (as a percent) | 100.00% | ||
Percentage of eligible compensation, matched 100% by employer | 6.00% | ||
Matching contribution to the plan | $ 88,348 | $ 85,676 | $ 116,873 |
Derivatives (Details)
Derivatives (Details) | 12 Months Ended | ||
Jun. 30, 2016USD ($)$ / bblbbl | Jun. 30, 2015USD ($) | Jun. 30, 2014USD ($) | |
Derivative [Line Items] | |||
Net asset position of derivatives with counterparty | $ 14,132 | ||
Gain on derivatives | 3,439,229 | ||
Gain on settled derivatives | 3,315,123 | ||
Net gain on unsettled derivatives | 124,106 | ||
(Gain) loss on derivative instruments, net | $ (3,439,229) | $ 109,974 | $ 0 |
Crude Oil | Options | |||
Derivative [Line Items] | |||
Volumes (in Bbls./day) | bbl | 600 | ||
Weighted Average Floor Price ($ per Bbl) | $ / bbl | 45 | ||
Weighted Average Ceiling Price ($ per Bbl) | $ / bbl | 55 | ||
Weighted Average Put Spread ($ per Bbl) | $ / bbl | 10 |
Fair Value Measurement - Assets
Fair Value Measurement - Assets and Liabilities Measured on Recurring Basis (Details) - Level 2 | Jun. 30, 2016USD ($) |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | |
Current derivative assets, Gross Amounts Recognized | $ 45,263 |
Current derivative assets, Gross Amounts Offset in the Consolidated Balance Sheet | (31,131) |
Current derivative assets, Net Amounts Presented in the Consolidated Balance Sheets | 14,132 |
Current derivative liabilities, Gross Amounts Recognized | (31,131) |
Current derivative liabilities, Gross Amounts Offset in the Consolidated Balance Sheet | 31,131 |
Current derivative liabilities, Net Amounts Presented in the Consolidated Balance Sheets | 0 |
Total, Gross Amounts Recognized | 14,132 |
Total, Gross Amounts Offset in the Consolidated Balance Sheet | 0 |
Total, Net Amounts Presented in the Consolidated Balance Sheets | $ 14,132 |
Supplemental Disclosures abou84
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of Costs Incurred and Capitalized in Oil and Natural Gas Property Acquisition, Exploration, and Development (Details) - USD ($) | 12 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Property acquisition costs: | ||||
Proved property | $ 0 | $ 0 | $ 0 | |
Unproved property | [1] | 596,500 | 0 | 47,344 |
Exploration costs | 0 | 0 | 757,423 | |
Development costs | 19,093,200 | 10,975,637 | 18,566 | |
Total costs incurred for oil and natural gas activities | $ 19,689,700 | $ 10,975,637 | $ 823,333 | |
[1] | As described in Note 3 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500. This cost is included in properties subject to amortization. |
Supplemental Disclosures abou85
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Estimated Quantities of Proved Oil and Natural Gas Reserves (Details) | 12 Months Ended | ||||||
Jun. 30, 2016BoeMcfbbl | Jun. 30, 2015BoeMcfbbl | Jun. 30, 2014BoeMcfbbl | Jun. 30, 2013BoeMcfbbl | ||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Balance at the beginning of the period (in BOE) | Boe | 12,446,394 | 13,289,510 | 13,766,440 | ||||
Revisions of previous estimates (in BOE) | Boe | (964,171) | [1] | (390,330) | [2] | (247,350) | [3] | |
Improved recovery, extensions and discoveries (in BOE) | Boe | 0 | 0 | 132,884 | ||||
Sales of minerals in place (in BOE) | Boe | 0 | 0 | (184,722) | ||||
Production (sales volumes) (in BOE) | Boe | (658,802) | (452,786) | (177,742) | ||||
Balance at the end of the period (in BOE) | Boe | 10,823,421 | 12,446,394 | 13,289,510 | ||||
Proved developed reserves (in BOE) | Boe | 7,168,249 | 7,349,626 | 7,970,562 | 10,089,861 | |||
Proved undeveloped reserves (in BOE) | Boe | 3,655,172 | 5,096,768 | 5,318,948 | 3,676,579 | |||
Delhi Field | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Revisions of previous estimates (in BOE) | Boe | 1,679,481 | ||||||
Crude Oil | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Balance at the beginning of the period (in Bbls/Mcf) | 10,011,976 | 10,526,344 | 12,782,755 | ||||
Revisions of previous estimates (in Bbls/Mcf) | (765,385) | [1] | (64,074) | [2] | (1,919,052) | [3] | |
Improved recovery, extensions and discoveries (in Bbls/Mcf) | 0 | 0 | 17,146 | ||||
Sales of minerals in place (in Bbls/Mcf) | 0 | 0 | (184,722) | ||||
Production (sales volumes) (in Bbls/Mcf) | (658,041) | (450,294) | (169,783) | ||||
Balance at the end of the period (in Bbls/Mcf) | 8,588,550 | 10,011,976 | 10,526,344 | ||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Proved developed reserves (in Bbls/Mcf) | 7,168,249 | 7,347,231 | 7,858,224 | 10,077,522 | |||
Proved undeveloped reserves (in Bbls/Mcf) | 1,420,301 | 2,664,745 | 2,668,120 | 2,705,233 | |||
Crude Oil | Delhi Field | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Revisions of previous estimates (in Bbls/Mcf) | 1,817,224 | ||||||
Natural Gas Liquids | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Balance at the beginning of the period (in Bbls/Mcf) | 2,433,595 | 2,278,688 | 979,885 | ||||
Revisions of previous estimates (in Bbls/Mcf) | (198,233) | [1] | 156,195 | [2] | 1,269,588 | [3] | |
Improved recovery, extensions and discoveries (in Bbls/Mcf) | 0 | 0 | 32,731 | ||||
Sales of minerals in place (in Bbls/Mcf) | 0 | 0 | 0 | ||||
Production (sales volumes) (in Bbls/Mcf) | (491) | (1,288) | (3,516) | ||||
Balance at the end of the period (in Bbls/Mcf) | 2,234,871 | 2,433,595 | 2,278,688 | ||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Proved developed reserves (in Bbls/Mcf) | 0 | 1,572 | 32,164 | 8,539 | |||
Proved undeveloped reserves (in Bbls/Mcf) | 2,234,871 | 2,432,023 | 2,246,524 | 971,346 | |||
Natural Gas Liquids | Giddings Field | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Revisions of previous estimates (in Bbls/Mcf) | (29,304) | ||||||
Natural Gas | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Balance at the beginning of the period (in Bbls/Mcf) | Mcf | 4,939 | 2,906,863 | 22,797 | ||||
Revisions of previous estimates (in Bbls/Mcf) | Mcf | (3,319) | [1] | (2,894,703) | [2] | 2,412,677 | [3] | |
Improved recovery, extensions and discoveries (in Bbls/Mcf) | Mcf | 0 | 0 | 498,044 | ||||
Sales of minerals in place (in Bbls/Mcf) | Mcf | 0 | 0 | 0 | ||||
Production (sales volumes) (in Bbls/Mcf) | Mcf | (1,620) | (7,221) | (26,655) | ||||
Balance at the end of the period (in Bbls/Mcf) | Mcf | 0 | 4,939 | 2,906,863 | ||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Proved developed reserves (in Bbls/Mcf) | Mcf | 0 | 4,939 | 481,042 | 22,797 | |||
Proved undeveloped reserves (in Bbls/Mcf) | Mcf | 0 | 0 | 2,425,821 | 0 | |||
Natural Gas | Delhi Field | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Revisions of previous estimates (in Bbls/Mcf) | Mcf | (2,246,524) | ||||||
Natural Gas | Giddings Field | |||||||
Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves | |||||||
Revisions of previous estimates (in Bbls/Mcf) | Mcf | (452,786) | ||||||
[1] | The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period. | ||||||
[2] | The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well. | ||||||
[3] | Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes. |
Supplemental Disclosures abou86
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Natural Gas Reserves (Details) - USD ($) | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | Jun. 30, 2013 |
Standardized measure of discounted future net cash flows | ||||
Future cash inflows | $ 383,491,193 | $ 807,030,282 | $ 1,193,515,075 | |
Future production costs and severance taxes | (179,182,565) | (309,225,333) | (475,387,931) | |
Future development costs | (16,595,047) | (49,691,006) | (46,154,178) | |
Future income tax expenses | (45,713,438) | (123,888,665) | (195,581,510) | |
Future net cash flows | 142,000,143 | 324,225,278 | 476,391,456 | |
10% annual discount for estimated timing of cash flows | (64,042,824) | (165,028,739) | (250,313,784) | |
Standardized measure of discounted future net cash flows | $ 77,957,319 | $ 159,196,539 | $ 226,077,672 | $ 307,220,699 |
Supplemental Disclosures abou87
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Schedule of NYMEX Prices Used in Determining Future Cash Flows (Details) | 12 Months Ended | ||
Jun. 30, 2016$ / bbl$ / MMBtu | Jun. 30, 2015$ / bbl$ / MMBtu | Jun. 30, 2014$ / bbl$ / MMBtu | |
Oil (per barrel) | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Commodity Prices Used in Determining Future Cash Flows | $ / bbl | 42.91 | 71.88 | 100.37 |
Gas (per million BTU) | |||
Average Sales Price and Production Costs Per Unit of Production [Line Items] | |||
Commodity Prices Used in Determining Future Cash Flows | $ / MMBtu | 0 | 3.44 | 4.10 |
Supplemental Disclosures abou88
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Roll Forward of Changes in Standardized Measure of Discount Future Cash Flows on Proved Crude Oil, Natural Gas Liquids, and Natural Gas Reserves (Details) - USD ($) | 12 Months Ended | |||
Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | ||
Changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves | ||||
Balance, beginning of year | $ 159,196,539 | $ 226,077,672 | $ 307,220,699 | |
Net changes in sales prices and production costs related to future production | (120,832,747) | (88,043,095) | (73,439,526) | |
Changes in estimated future development costs | 74,991 | (9,585,405) | 9,848,614 | |
Sales of oil and gas produced during the period, net of production costs | (17,079,363) | (18,538,016) | (16,479,934) | |
Net change due to extensions, discoveries, and improved recovery | 0 | 0 | 775,574 | |
Net change due to revisions in quantity estimates | (18,821,014) | (9,391,321) | (23,757,788) | |
Net change due to sales of minerals in place | 0 | 0 | (3,150,277) | |
Development costs incurred during the period | 16,327,883 | 7,785,095 | 0 | |
Accretion of discount | 21,870,650 | 31,974,540 | 45,896,187 | |
Net change in discounted income taxes | 36,598,239 | 34,157,767 | 58,073,450 | |
Net changes in timing of production and other | [1] | 622,141 | (15,240,698) | (78,909,327) |
Balance, end of year | $ 77,957,319 | $ 159,196,539 | $ 226,077,672 | |
[1] | Due to the June 2013 fluid release event in the Delhi field, the operator expressed plans to produce the Delhi field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014. |
Supplemental Disclosures abou89
Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited) - Narrative (Details) | Jun. 24, 2016USD ($) | Jun. 30, 2016USD ($)BoeMcfbbl | Jun. 30, 2015USD ($)BoeMcfbbl | Jun. 30, 2014USD ($)BoeMcfbbl | |||
Reserve Quantities [Line Items] | |||||||
Oil and natural gas property costs attributable to the recognition of asset retirement obligations | $ | $ 140,151 | $ 576,039 | $ 66,976 | ||||
Fair value of litigation settlement | $ | $ 596,500 | $ 0 | $ 0 | ||||
Period Considered for Unweighted Arithmetic Average for Determining Reserve Volumes and Values | 12 months | ||||||
Positive revision of previous estimate (in BOE) | Boe | (964,171) | [1] | (390,330) | [2] | (247,350) | [3] | |
Period Considered for Determining Unweighted Arithmetic Average of First Day of Month, Commodity Prices | 12 months | ||||||
Crude Oil | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | (765,385) | [1] | (64,074) | [2] | (1,919,052) | [3] | |
Natural Gas Liquids | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | (198,233) | [1] | 156,195 | [2] | 1,269,588 | [3] | |
Revision due to improved design (in Bbls/Mcf) | 185,499 | ||||||
Natural Gas | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf | (3,319) | [1] | (2,894,703) | [2] | 2,412,677 | [3] | |
Delhi Field | |||||||
Reserve Quantities [Line Items] | |||||||
Positive revision of previous estimate (in BOE) | Boe | 1,679,481 | ||||||
Delhi Field | Crude Oil | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | 1,817,224 | ||||||
Delhi Field | Natural Gas Liquids | |||||||
Reserve Quantities [Line Items] | |||||||
Revision due to improved design (in Bbls/Mcf) | 1,275,178 | ||||||
Delhi Field | Natural Gas | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf | (2,246,524) | ||||||
Revision due to improved design (in Bbls/Mcf) | Mcf | 2,425,821 | ||||||
Giddings Field | Natural Gas Liquids | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | (29,304) | ||||||
Giddings Field | Natural Gas | |||||||
Reserve Quantities [Line Items] | |||||||
Revision increase(decrease) of previous estimates (in Bbls/Mcf) | Mcf | (452,786) | ||||||
Dehli Field Litigation | Denbury Resources, Inc | |||||||
Reserve Quantities [Line Items] | |||||||
Working interest in Mengal Sand Interval | 23.90% | ||||||
Fair value of litigation settlement | $ | $ 596,500 | ||||||
[1] | The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period. | ||||||
[2] | The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi field NGL plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned NGL plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well. | ||||||
[3] | Significant reserve revisions occurred in the Delhi field during fiscal 2014. As a result of a fluid release event in the field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO2 injections in certain parts of the field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the NGL plant in the Delhi field. The plant was expected to significantly increase recoveries of these products, particularly natural gas, which were not previously planned to be extracted from the injection volumes. |
Selected Quarterly Financial 90
Selected Quarterly Financial Data (Unaudited) - Summary of Quarterly Financial Information (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||||||||||||
Jun. 30, 2016 | [1] | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2016 | Jun. 30, 2015 | Jun. 30, 2014 | |||
Revenues | $ 7,240,434 | $ 5,106,735 | $ 6,622,927 | [2] | $ 7,379,406 | $ 9,063,682 | $ 7,064,689 | $ 7,708,067 | [3] | $ 4,004,827 | $ 26,349,502 | $ 27,841,265 | $ 17,673,508 | |
Operating income (loss) | 954,823 | (681,147) | (454,987) | [2] | 1,846,498 | 3,334,547 | 1,245,990 | 2,162,294 | [3] | 1,840,866 | 1,665,187 | 8,583,697 | 5,528,147 | |
Net income (loss) available to common shareholders | $ 20,705,894 | $ (298,183) | $ 654,697 | [2] | $ 2,923,652 | $ 1,719,767 | $ 566,011 | $ 1,071,342 | [3] | $ 960,435 | $ 23,986,060 | $ 4,317,555 | $ 2,923,011 | |
Basic net income (loss) per share (in dollars per share) | $ 0.63 | $ (0.01) | $ 0.02 | [2] | $ 0.09 | $ 0.05 | $ 0.02 | $ 0.03 | [3] | $ 0.03 | $ 0.73 | $ 0.13 | $ 0.09 | |
Diluted net income (loss) per share (in dollars per share) | $ 0.63 | $ (0.01) | $ 0.02 | [2] | $ 0.09 | $ 0.05 | $ 0.02 | $ 0.03 | [3] | $ 0.03 | $ 0.73 | $ 0.13 | $ 0.09 | |
Restructuring charges | $ 1,300,000 | $ 1,257,433 | $ (5,431) | $ 1,293,186 | ||||||||||
Delhi field litigation settlement gain | 28,096,500 | $ 0 | $ 0 | |||||||||||
Delhi Field | ||||||||||||||
Working interest | 23.90% | |||||||||||||
Net revenue interest | 19.00% | |||||||||||||
Dehli Field Litigation | ||||||||||||||
Delhi field litigation settlement gain | $ 28,100,000 | |||||||||||||
[1] | Includes gain on settlement of Delhi field litigation of $28.1 million. | |||||||||||||
[2] | Includes $1.3 million restructuring charge. | |||||||||||||
[3] | Impacted by the November 1, 2014 reversion of the Company's 23.9% working interest and 19.0% net revenue interest in the Delhi field. |