Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Aug. 31, 2015 | Oct. 10, 2015 | Feb. 28, 2015 | |
Document And Entity Information [Abstract] | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Aug. 31, 2015 | ||
Entity Registrant Name | SYNERGY RESOURCES CORP | ||
Entity Central Index Key | 1,413,507 | ||
Current Fiscal Year End Date | --08-31 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,015 | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 105,111,133 | ||
Entity Public Float | $ 1.1 | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes |
BALANCE SHEETS
BALANCE SHEETS - USD ($) $ in Thousands | Aug. 31, 2015 | Aug. 31, 2014 |
Current assets: | ||
Cash and cash equivalents | $ 133,908 | $ 34,753 |
Accounts receivable: | ||
Oil and gas sales | 13,601 | 16,974 |
Joint interest billing and other | 15,325 | 15,398 |
Commodity derivative | 2,897 | 365 |
Other current assets | 1,109 | 750 |
Total current assets | 166,840 | 68,240 |
Property and equipment: | ||
Proved properties, net | 452,393 | 275,018 |
Unproved properties and properties under development, not being amortized | 77,564 | 95,278 |
Other property and equipment, net | 4,783 | 9,104 |
Total property and equipment, net | 534,740 | 379,400 |
Commodity derivative | 1,565 | 54 |
Goodwill | 40,711 | 0 |
Other assets | 2,593 | 848 |
Total assets | 746,449 | 448,542 |
Current liabilities: | ||
Trade accounts payable | 670 | 1,747 |
Well costs payable | 33,071 | 71,849 |
Revenue payable | 19,044 | 14,487 |
Production taxes payable | 20,899 | 14,376 |
Other accrued expenses | 27 | 817 |
Commodity derivative | 302 | |
Total current liabilities | 73,711 | 103,578 |
Revolving credit facility | 78,000 | 37,000 |
Commodity derivative | 0 | 307 |
Deferred tax liability, net | 10,007 | 21,437 |
Asset retirement obligations | 12,334 | 4,730 |
Total liabilities | $ 174,052 | $ 167,052 |
Commitments and contingencies | ||
Shareholders' equity: | ||
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding | $ 0 | $ 0 |
Common stock - $0.001 par value, 200,000,000 shares authorized: 105,099,342 and 77,999,082 shares issued and outstanding, respectively | 105 | 78 |
Additional paid-in capital | 538,631 | 265,793 |
Retained earnings (accumulated deficit) | 33,661 | 15,619 |
Total shareholders' equity | 572,397 | 281,490 |
Total liabilities and shareholders' equity | $ 746,449 | $ 448,542 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - $ / shares | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 |
Statement of Financial Position [Abstract] | |||
Preferred stock, par value per share | $ 0.01 | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 |
Preferred stock, shares issued | 0 | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 | 0 |
Common stock, par value per share | $ 0.001 | $ 0.001 | $ 0.001 |
Common stock, shares authorized | 200,000,000 | 200,000,000 | 100,000,000 |
Common stock, shares issued | 105,099,342 | 77,999,082 | 70,587,723 |
Common stock, shares outstanding | 105,099,342 | 77,999,082 | 70,587,723 |
STATEMENTS OF OPERATIONS
STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Income Statement [Abstract] | |||
Oil and gas revenues | $ 124,843 | $ 104,219 | $ 46,223 |
Expenses | |||
Lease operating expenses | 15,017 | 7,991 | 3,417 |
Production taxes | 11,340 | 9,667 | 4,237 |
Depreciation, depletion, accretion, and amortization | 65,869 | 32,958 | 13,336 |
Full cost ceiling impairment | 16,000 | 0 | 0 |
General and administrative | 18,995 | 10,139 | 5,688 |
Total expenses | 127,221 | 60,755 | 26,678 |
Operating (loss) income | (2,378) | 43,464 | 19,545 |
Other income (expense) | |||
Commodity derivative realized gain (loss) | 30,466 | (2,138) | (395) |
Commodity derivative unrealized gain (loss) | 1,790 | 2,459 | (2,649) |
Interest expense, net | (245) | 0 | (97) |
Interest income | 86 | 82 | 47 |
Total other income (expense) | 32,097 | 403 | (3,094) |
Income before income taxes | 29,719 | 43,867 | 16,451 |
Income tax provision | 11,677 | 15,014 | 6,870 |
Net income | $ 18,042 | $ 28,853 | $ 9,581 |
Net income per common share: | |||
Basic (in dollars per share) | $ 0.19 | $ 0.38 | $ 0.17 |
Diluted (in dollars per share) | $ 0.19 | $ 0.37 | $ 0.16 |
Weighted average shares outstanding: | |||
Basic (in shares) | 94,628,665 | 76,214,737 | 57,089,362 |
Diluted (in shares) | 95,319,269 | 77,808,054 | 59,088,761 |
STATEMENT OF CHANGES IN SHAREHO
STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY - USD ($) $ in Thousands | Total | Common Stock [Member] | Additional Paid-In Capital [Member] | Accumulated Earnings (Deficit) [Member] |
Balance at Aug. 31, 2012 | $ 101,113 | $ 52 | $ 123,876 | $ (22,815) |
Balance, shares at Aug. 31, 2012 | 51,409,340 | |||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued for acquisition | $ 13,518 | $ 3 | 13,515 | |
Shares issued for acquisition, shares | 3,128,422 | 3,128,422 | ||
Shares issued in exchange for mineral leases and services | $ 3,166 | $ 1 | 3,165 | |
Shares issued in exchange for mineral leases and services, shares | 687,122 | 687,122 | ||
Shares issued for cash, net of offering costs | $ 78,243 | $ 13 | 78,230 | |
Shares issued for cash, net of offering costs, shares | 13,225,000 | 13,225,000 | ||
Shares issued for exercise of warrants | $ 3,275 | $ 1 | 3,274 | |
Shares issued for exercise of warrants, shares | 1,052,698 | |||
Payment of tax withholdings using withheld shares | (6,990) | (6,990) | ||
Shares issued for exercise of stock option and stock grants | $ 0 | $ 1 | (1) | |
Shares issued for exercise of stock options, shares | 2,120,000 | 1,030,057 | ||
Stock based compensation | $ 1,314 | 1,314 | ||
Stock based compensation, shares | 55,084 | |||
Net income | 9,581 | 9,581 | ||
Balance at Aug. 31, 2013 | $ 203,220 | $ 71 | 216,383 | (13,234) |
Balance, shares at Aug. 31, 2013 | 70,587,723 | 70,587,723 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued for acquisition | $ 8,328 | $ 1 | 8,327 | |
Shares issued for acquisition, shares | 872,483 | 872,483 | ||
Shares issued in exchange for mineral leases and services | $ 2,856 | 2,856 | ||
Shares issued in exchange for mineral leases and services, shares | 357,901 | 357,901 | ||
Shares issued for cash, net of offering costs, shares | 0 | |||
Shares issued for exercise of warrants | $ 35,634 | $ 6 | 35,628 | |
Shares issued for exercise of warrants, shares | 6,063,801 | |||
Payment of tax withholdings using withheld shares | (369) | (369) | ||
Shares issued for exercise of stock option and stock grants | $ 0 | |||
Shares issued for exercise of stock options, shares | 61,000 | 27,299 | ||
Shares issued under stock bonus plan | $ 1,201 | 1,201 | ||
Shares issued under stock bonus plan, shares | 89,875 | |||
Stock based compensation | 1,767 | 1,767 | ||
Stock based compensation, shares | 0 | |||
Net income | 28,853 | 28,853 | ||
Balance at Aug. 31, 2014 | $ 281,490 | $ 78 | 265,793 | 15,619 |
Balance, shares at Aug. 31, 2014 | 77,999,082 | 77,999,082 | ||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||||
Shares issued for acquisition | $ 48,434 | $ 5 | 48,429 | |
Shares issued for acquisition, shares | 4,648,136 | 4,648,136 | ||
Shares issued in exchange for mineral leases and services | $ 11,787 | $ 1 | 11,786 | |
Shares issued in exchange for mineral leases and services, shares | 995,672 | 995,672 | ||
Shares issued for cash, net of offering costs | $ 190,845 | $ 19 | 190,826 | |
Shares issued for cash, net of offering costs, shares | 18,613,952 | 18,613,952 | ||
Shares issued for exercise of warrants | $ 15,370 | $ 2 | 15,368 | |
Shares issued for exercise of warrants, shares | 2,562,473 | |||
Payment of tax withholdings using withheld shares | (1,262) | (1,262) | ||
Shares issued for exercise of stock option and stock grants | $ 0 | |||
Shares issued for exercise of stock options, shares | 258,000 | 118,272 | ||
Shares issued under stock bonus plan | $ 2,950 | 2,950 | ||
Shares issued under stock bonus plan, shares | 161,755 | |||
Stock based compensation | 4,741 | 4,741 | ||
Stock based compensation, shares | 0 | |||
Net income | 18,042 | 18,042 | ||
Balance at Aug. 31, 2015 | $ 572,397 | $ 105 | $ 538,631 | $ 33,661 |
Balance, shares at Aug. 31, 2015 | 105,099,342 | 105,099,342 |
STATEMENT OF CHANGES IN SHAREH6
STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY (Parenthetical) - USD ($) $ in Thousands | 12 Months Ended | |
Aug. 31, 2015 | Aug. 31, 2013 | |
Statement of Stockholders' Equity [Abstract] | ||
Price per share for shares issued for cash (in dollars per share) | $ 10.75 | $ 6.25 |
Offering costs | $ (9,255) | $ (4,413) |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Cash flows from operating activities: | |||
Net income | $ 18,042 | $ 28,853 | $ 9,581 |
Adjustments to reconcile net income to net cash provided by operating activities: | |||
Depletion, depreciation, and amortization | 65,869 | 32,958 | 13,336 |
Full cost ceiling impairment | 16,000 | 0 | 0 |
Provision for deferred taxes | 11,679 | 15,014 | 6,870 |
Stock-based compensation | 7,691 | 2,968 | 1,362 |
Cash settlements on commodity derivative contracts | 31,721 | (2,138) | (395) |
Cash premiums paid for commodity derivative contracts | (4,117) | 0 | 0 |
(Gain) loss on commodity derivatives contracts | (32,256) | (321) | 3,044 |
Accounts receivable | |||
Oil and gas sales | 3,373 | (9,613) | (3,756) |
Joint interest billing | 73 | (10,698) | (1,432) |
Accounts payable | |||
Trade | (1,077) | 798 | (550) |
Revenue | 4,557 | 8,406 | 1,921 |
Production taxes | 5,121 | 8,099 | 2,472 |
Accrued expenses | (1,230) | 448 | (141) |
Other | (359) | 131 | (192) |
Total adjustments | 107,045 | 46,052 | 22,539 |
Net cash provided by operating activities | 125,087 | 74,905 | 32,120 |
Cash flows from investing activities: | |||
Acquisition of property and equipment | (275,808) | (155,602) | (80,469) |
Short-term investments | 0 | 60,018 | (60,000) |
Net proceeds from sales of oil and gas properties | 6,239 | 704 | 0 |
Net cash used in investing activities | (269,569) | (94,880) | (140,469) |
Cash flows from financing activities: | |||
Proceeds from sale of stock | 200,100 | 0 | 82,656 |
Offering costs | (9,255) | 0 | (4,413) |
Proceeds from exercise of warrants | 15,370 | 35,634 | 3,275 |
Shares withheld for payment of employee payroll taxes | (1,262) | (369) | (6,990) |
Proceeds from revolving credit facility | 186,000 | 0 | 34,000 |
Principal repayments on revolving credit facility | (145,000) | 0 | 0 |
Financing fee | (2,316) | 0 | 0 |
Net cash provided by financing activities | 243,637 | 35,265 | 108,528 |
Net increase in cash and equivalents | 99,155 | 15,290 | 179 |
Cash and equivalents at beginning of period | 34,753 | 19,463 | 19,284 |
Cash and equivalents at end of period | $ 133,908 | $ 34,753 | $ 19,463 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Aug. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Summary of Significant Accounting Policies | Organization and Summary of Significant Accounting Policies Organization : Synergy Resources Corporation (the “Company”) is engaged in oil and gas acquisition, exploration, development and production activities, primarily in the Denver-Julesburg Basin ("D-J Basin") of Colorado. The Company’s common stock is listed and traded on the NYSE MKT under the symbol “SYRG.” Basis of Presentation: The Company has adopted August 31st as the end of its fiscal year. The Company does not utilize any special purpose entities. The Company operates in one business segment and all of its operations are located in the United States of America. At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees. The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). Use of Estimates: The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves and goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from these estimates. Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. Short-Term Investments: As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year. Inventory: Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market. Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result of which is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depreciation, depletion, and amortization, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period, unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well. Oil and Gas Reserves: Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company’s oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves. Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and exploration and development projects that are not subject to current amortization. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 9 for additional information. Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands). For the Years Ended August 31, 2015 2014 2013 Capitalized overhead $ 2,049 $ 1,230 $ 637 Well Costs Payable: The cost of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings (“JIB”). For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure. Other Property and Equipment: Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years. Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk-free interest rate. Estimates are periodically reviewed and adjusted to reflect changes. The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. This is typically when a well is completed or an asset is placed in service. When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment. Business Combinations: The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. Goodwill: Goodwill results from business combinations and represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually, or more often if events or circumstances indicate that the fair value of a reporting unit may have been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings. During the year ended August 31, 2015 , the Company did not recognize an impairment to goodwill. Oil and Gas Sales: The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. Major Customers: The Company sells production to a small number of customers, as is customary in the industry. As a result, during the fiscal years ended August 31, 2015 , 2014 and 2013 , certain of the Company’s customers represented 10% or more of its oil and gas revenue (“major customers”). For the fiscal year ended August 31, 2015 , the Company had two major customers, which represented 65% and 11% of its revenue during the period. For the fiscal year ended August 31, 2014 , the Company had two major customers, which represented 54% and 13% of its revenue during the period. For the fiscal year ended August 31, 2013 , the Company had two major customers, which represented 50% and 15% of its revenue during the period. Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer. Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners. Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table: As of August 31, 2015 2014 2013 Company A 30% 37% 24% Company B * * 23% Company C * * 12% * less than 10% The Company operates exclusively within the United States of America and, except for cash and short-term investments, all of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry. Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities. Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For restricted stock awards, fair value is the closing stock price for the Company's common stock on the grant date. The expense is recognized over the vesting period of the grant. See Note 11 for additional information. Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No significant uncertain tax positions were identified as of any date on or before August 31, 2015 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of August 31, 2015 , the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 12 for further information. Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or “no premium” collars to reduce the effect of price changes on a portion of its future oil and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7 . Earnings Per Share Amounts: Basic earnings per share includes no dilution and is computed by dividing net income by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, non-vested restricted stock, and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share. The following table sets forth the share calculation of diluted earnings per share: For the Years Ended August 31, 2015 2014 2013 Weighted-average shares outstanding - basic 94,628,665 76,214,737 57,089,362 Potentially dilutive common shares from: Stock options 672,493 479,222 1,881,682 Restricted stock 18,111 — — Warrants — 1,114,095 117,717 Weighted-average shares outstanding - diluted 95,319,269 77,808,054 59,088,761 The following potentially dilutive securities outstanding for the fiscal years presented were not included in the respective earnings per share calculation above, as such securities had an anti-dilutive effect on earnings per share: For the Years Ended August 31, 2015 2014 2013 Potentially dilutive common shares from: Stock options 2,785,500 533,000 670,000 Restricted stock 145,000 — — Warrants — — 8,500,000 Total 2,930,500 533,000 9,170,000 Recent Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. In January 2015, the FASB issued Accounting Standards Update 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items” (“ASU 2015-01”), which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently. The standard is effective prospectively for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption. Adoption of ASU 2015-01 is not expected to have a material effect on our financial position, results of operations, or cash flows. In November 2014, the FASB issued Accounting Standards Update 2014-16, “Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity” (“ASU 2014-16”), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument. An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features. ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on the Company's financial position or results of operations. In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2016 including interim periods within that period. Early adoption is not permitted. We are currently evaluating which transition approach to use and the impact of the adoption of this standard on our consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements. There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations or cash flows. |
Property and Equipment
Property and Equipment | 12 Months Ended |
Aug. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Property and Equipment | Property and Equipment The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of August 31, 2015 2014 Oil and gas properties, full cost method: Unevaluated costs, not subject to amortization: Lease acquisition and other costs $ 58,068 $ 41,531 Wells in progress 19,496 53,747 Subtotal, unevaluated costs 77,564 95,278 Evaluated costs: Producing and non-producing 588,802 329,926 Total capitalized costs 666,366 425,204 Less, accumulated depletion and full cost ceiling impairments (136,409 ) (54,908 ) Oil and gas properties, net 529,957 370,296 Land 4,478 3,898 Other property and equipment 875 5,961 Less, accumulated depreciation (570 ) (755 ) Other property and equipment, net 4,783 9,104 Total property and equipment, net $ 534,740 $ 379,400 The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. Under the ceiling test, the value of the Company’s reserves is calculated using the average of the published spot prices for WTI oil (per barrel) as of the first day of each of the previous twelve months, as well as the average of the published spot prices for Henry Hub (per MMBtu) as of the first day of each of the previous twelve months, each adjusted by lease or field for quality, transportation fees and regional price differentials. The ceiling test used average realized prices of $53.27 per barrel and $3.28 per MMBtu. The oil prices used at August 31, 2015 were approximately 40% lower than the prices used at August 31, 2014 . Using these prices, the Company's net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $16 million at August 31, 2015 , resulting in immediate recognition of a ceiling test impairment. No such cost ceiling test impairment was recognized during the fiscal years ended August 31, 2014 and 2013 . The Company also reviews the fair value of its unproved properties. The review for the fiscal year ended August 31, 2015 indicated that estimated carrying values of such assets exceeded fair values. Therefore, the Company recorded an impairment of $15.4 million , and these costs were moved into the full cost pool and subject to the aforementioned ceiling test. No such impairments were recognized during the fiscal year ended August 31, 2014 . In addition, during the year ended August 31, 2015 , certain amounts previously recorded were reclassified from one category to another without changing the total amounts recorded as property and equipment. Specifically, costs associated with a disposal well and related equipment were reclassified from other property and equipment into producing oil and gas properties to more closely reflect use of the disposal well to process flow-back water from oil and gas operations. Similarly, accumulated depreciation associated with the disposal well was reclassified from accumulated depreciation to accumulated depletion. The updated classification for the disposal well, related equipment, and accumulated depreciation did not require a change to previously reported depletion, depreciation, and amortization expense (“DDA”). Secondly, as discussed in Note 3 , the analysis of assets acquired in the 2014 business combination transactions with Apollo and Trilogy were completed and fair values associated with probable horizontal well development were reclassified from proved properties into unproved properties. Costs Incurred: Costs incurred in oil and gas property acquisition, exploration and development activities for the fiscal years presented were (in thousands): For the Years Ended August 31, 2015 2014 2013 Acquisition of property: Unproved $ 32,701 $ 15,002 $ 12,295 Proved 51,400 33,795 43,143 Exploration costs 146,892 43,089 — Development costs 4,957 111,238 61,128 Other property and equipment 741 9,315 — Asset retirement obligation 7,051 1,610 1,578 Total costs incurred $ 243,742 $ 214,049 $ 118,144 Capitalized Costs Excluded from Amortization: The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to depletion, depreciation, and amortization at August 31, 2015 (in thousands). Period Incurred Total as of 2015 2014 2013 2012 and prior August 31, 2015 Unproved leasehold acquisition costs $ 32,701 $ 8,246 $ 8,007 $ 9,114 $ 58,068 Unevaluated development costs 19,496 — — — 19,496 Total unevaluated costs $ 52,197 $ 8,246 $ 8,007 $ 9,114 $ 77,564 There were no individually significant properties or significant development projects included in the Company’s unevaluated property balance. The Company regularly evaluates these costs to determine whether impairment has occurred. The majority of these costs are expected to be evaluated and included in the amortization base within three years . |
Acquisitions
Acquisitions | 12 Months Ended |
Aug. 31, 2015 | |
Business Combinations [Abstract] | |
Acquisitions | Acquisitions During the fiscal years ended August 31, 2015 and 2014 , the Company acquired certain oil and gas and other assets, as described below. Bayswater transaction On December 15, 2014, the Company completed the acquisition of certain assets from three independent oil and gas companies (collectively known as “Bayswater”) for a total purchase price of $126.0 million , net of customary closing adjustments. The purchase price was composed of $74.2 million in cash and $48.4 million in restricted common stock plus the assumption of certain liabilities. The Bayswater acquisition encompassed 4,227 net acres with rights to the Codell and Niobrara formations, and 1,480 net acres with rights to other formations including the Sussex, Shannon and J-Sand. Additionally, the Company acquired non-operated working interests in 17 horizontal wells, and 73 operated vertical wells as well as working interests in 11 non-operated vertical wells. The working interests in the horizontal wells range from 6% to 40% while the working interests in the vertical wells range from 5% to 100% . The purpose of the transaction was to provide additional mineral acres upon which the Company could drill wells and produce hydrocarbons. It is believed that the transaction will improve the Company's cash flow and earnings per share. The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of December 15, 2014. Transaction costs related to the Bayswater acquisition were expensed as incurred. The following table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price December 15, 2014 Consideration given: Cash $ 74,221 Synergy Resources Corp. Common Stock (1) 48,434 Net liabilities assumed, including asset retirement obligations 3,315 Total consideration given $ 125,970 Allocation of Purchase Price Proved oil and gas properties (2) $ 51,400 Unproved oil and gas properties 6,500 Other assets, including accounts receivable 3,392 Deferred tax asset 23,967 Total fair value of assets acquired $ 85,259 Goodwill $ 40,711 (1) The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 ( 4,648,136 shares at $10.42 per share). (2) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10% , and assumptions on the timing and amount of future development and operating costs. The fair value analysis concluded that the purchase price exceeded the fair value of assets acquired. Accordingly, goodwill was recognized for book purposes. For tax purposes, no goodwill has been recognized as the entire purchase price was allocated to proved and unproved oil and gas properties. The difference between the book and tax basis of oil and gas properties created a deferred tax asset of $24.0 million . In the accompanying balance sheet, the deferred tax asset was offset against deferred liabilities. The amount allocated to goodwill as a result of the Bayswater acquisition totaled $40.7 million for book purposes. Goodwill is primarily attributable to the operational and financial benefits expected to be realized from the acquisition, including employing optimized completion techniques on Bayswater's undrilled acreage which will improve hydrocarbon recovery, realized savings in drilling and well completion costs, functional synergies due to geographic location, and the ability to participate in future commodity price increase. Differences between the preliminary allocation and final allocation of the purchase price were treated as a change in accounting estimate, and no retroactive adjustments were made to previously reported financial statements. The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves. The final analysis concluded that the fair value of unproved oil and gas properties was $6.5 million and that fair value should be attributed to deferred tax assets and goodwill. The re-allocation of $64.7 million from unproved properties not subject to amortization to goodwill and deferred tax asset did not impact the full cost amortization base, and no prior period adjustment was necessary. The results of operations of Bayswater from the December 15, 2014 closing date through August 31, 2015, representing approximately $7.7 million of revenue and $4.8 million of net income, have been included in the Company's consolidated statement of operations for the year ended August 31, 2015. The following table presents the pro forma combined results of operations for the two years ended August 31, 2015 as if the Bayswater transaction had occurred on September 1, 2013, the first day of our 2014 fiscal year. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition and operating costs incurred as a result of the assets acquired. The unaudited pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The unaudited pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Year Ended August 31, (in thousands) 2015 2014 Oil and gas revenues $ 131,716 $ 108,740 Net income $ 19,822 $ 27,720 Earnings per common share Basic $ 0.21 $ 0.34 Diluted $ 0.21 $ 0.34 2014 transactions During the year ended August 31, 2014, the Company closed on two transactions that qualified as Business Combinations under ASC 805. The initial accounting treatment of the transactions was based upon the preliminary analysis of the assets acquired. During the first fiscal quarter of 2015, the Company completed its analysis and finalized the allocation of purchase price to the assets acquired. The values presented in this Note, including the tables herein, present the final result of the analysis. Trilogy transaction On September 16, 2013, the Company entered into a definitive purchase and sale agreement with Trilogy Resources, LLC (“Trilogy”), for its interests in 21 producing oil and gas wells and approximately 800 net mineral acres (the “Trilogy Assets”). On November 12, 2013, the Company closed the transaction for a combination of cash and stock. Trilogy received 301,339 shares of the Company’s common stock valued at $2.9 million and cash consideration of approximately $15.9 million . No material transaction costs were incurred in connection with this acquisition. The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 12, 2013. The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price November 12, 2013 Consideration given: Cash $ 15,902 Synergy Resources Corp. Common Stock * 2,896 Net liabilities assumed, including asset retirement obligations 977 Total consideration given $ 19,775 Allocation of Purchase Price Proved oil and gas properties $ 11,514 Unproved oil and gas properties 7,725 Other assets, including accounts receivable 536 Total fair value of assets acquired $ 19,775 * The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013 ( 301,339 shares at $9.61 per share). Apollo transaction On August 27, 2013, the Company entered into a definitive purchase and sale agreement (“the Agreement”), with Apollo Operating, LLC (“Apollo”), for its interests in 38 producing oil and gas wells, partial interest ( 25% ) in one water disposal well (the “Disposal Well”), and approximately 3,639 gross ( 1,000 net) mineral acres (“the Apollo Operating Assets”). On November 13, 2013, the Company closed the transaction for a combination of cash and stock. Apollo received cash consideration of approximately $11.0 million and 550,518 shares of the Company’s common stock valued at $5.2 million . Following the Company’s acquisition of the Apollo Operating Assets, the Company acquired all other remaining interests in the Disposal Well (the “Related Interests”) through several transactions with the individual owners of such interests. The Company acquired the Related Interests for approximately $3.7 million in cash consideration and 20,626 shares of the Company’s common stock, valued at $0.2 million . No material transaction costs were incurred in connection with this acquisition. The acquisition was accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 13, 2013. The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price November 13, 2013 Consideration given: Cash $ 14,688 Synergy Resources Corp. Common Stock * 5,432 Net liabilities assumed, including asset retirement obligation 1,403 Total consideration given $ 21,523 Allocation of Purchase Price Proved oil and gas properties $ 13,284 Unproved oil and gas properties 7,577 Other assets, including accounts receivable 662 Total fair value of assets acquired $ 21,523 * The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08 ). The motivation for both the Trilogy and Apollo acquisitions was the expectation that each was accretive to cash flow and earnings per share. The acquisitions qualify as business combinations, and as such, the Company estimated the fair value of each property as of the acquisition date (the date on which the Company obtained control of the properties). Fair value measurements utilize assumptions of market participants. To determine the fair value of the oil and gas assets, the Company used an income approach based on a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. The Company determined the appropriate discount rates used for the discounted cash flow analyses by using a weighted-average cost of capital from a market participant perspective plus property-specific risk premiums for the assets acquired. The Company estimated property-specific risk premiums taking into consideration the gas-to-oil ratio of the related reserves, among other items. Given the unobservable nature of the significant inputs, they are deemed to be Level 3 in the fair value hierarchy. The working capital assets acquired were determined to be at fair value due to their short-term nature. The preliminary analysis and allocation of the purchase price focused on the values inherent in the proved producing wells and the associated proved undeveloped reserves. All of the producing wells acquired in the transactions were vertical wells and the initial estimates allocated 100% of the fair value to proved properties associated with vertical well development. The final analysis also considered the additional value provided by virtue of the ability to drill horizontal wells in the acquired acreage. Adding horizontal wells to the development plan required a further evaluation as to the classification of the horizontal reserves, as reserves classified as proved under a vertical well drilling plan may be classified differently under a horizontal drilling plan. In the subject acres, the horizontal well reserves are classified as unproved even though the vertical well reserves are proved. Thus, the final analysis attributed $15.3 million of fair value to unproved horizontal properties and $24.8 million of fair value to proved properties. Differences between the preliminary allocation and final allocation of acquired fair value have been treated as a change in accounting estimate, and no retroactive adjustments were made to the previously reported financial statements. Furthermore, since the reclassification of $15.3 million from proved properties subject to amortization to unproved properties not subject to amortization represents approximately 2% of the full cost amortization base, no prior period adjustment was recorded during the current year. The following table presents the pro forma combined results of operations for the two years ended August 31, 2014 and 2013 as if the Trilogy and Apollo transactions had occurred on September 1, 2012, the first day of our 2013 fiscal year. The unaudited pro forma results reflect significant pro forma adjustments related to funding the acquisition through the issuance of common stock and cash, additional depreciation expense, costs directly attributable to the acquisition and operating costs incurred as a result of the assets acquired. The unaudited pro forma results do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The unaudited pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Year Ended August 31, (in thousands) 2014 2013 Oil and gas revenues $ 106,584 $ 55,633 Net income $ 29,681 $ 13,191 Earnings per common share Basic $ 0.39 $ 0.23 Diluted $ 0.38 $ 0.22 |
Depletion, depreciation and amo
Depletion, depreciation and amortization ("DDA") | 12 Months Ended |
Aug. 31, 2015 | |
Other Costs and Disclosures [Abstract] | |
Depletion, depreciation and amortization ("DDA") | Depletion, depreciation, accretion, and amortization (“DDA”) Depletion, depreciation, accretion, and amortization consisted of the following (in thousands): For the Years Ended August 31, 2015 2014 2013 Depletion of oil and gas properties $ 65,158 $ 32,132 $ 13,046 Depreciation, accretion, and amortization 711 826 290 Total DDA Expense $ 65,869 $ 32,958 $ 13,336 Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total reserves at the beginning of the quarter. For the fiscal year ended August 31, 2015 , production of 3,194 MBOE represented 5.3% of estimated total proved reserves. For the fiscal year ended August 31, 2014 , production of 1,566 MBOE represented 4.6% of estimated total proved reserves. DDA expense was $20.62 per BOE, $21.05 per BOE, and $17.26 per BOE for the years ended August 31, 2015 , 2014 , and 2013 , respectively. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Aug. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligations | Asset Retirement Obligations Upon completion or acquisition of a well, the Company recognizes obligations for its oil and gas operations for anticipated costs to remove and dispose of surface equipment, plug and abandon the wells, and restore the drilling sites to its original use. The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in regulations. Changes in estimates are reflected in the obligations as they occur. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions: For the Years Ended August 31, 2015 2014 Inflation rate 3.90% 3.90% Estimated asset life 16.0 - 30.0 years 25.0 - 39.0 years Credit adjusted risk free interest rate 8% 8% The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands). As of August 31, 2015 2014 Beginning asset retirement obligation $ 4,730 $ 2,777 Liabilities incurred 1,372 1,024 Liabilities assumed 1,913 586 Accretion expense 553 343 Revisions in previous estimates 3,766 — $ 12,334 $ 4,730 During fiscal 2015, the Company increased its asset retirement obligation by $3.8 million due to revising its assumption of the average cost to plug and abandon each well. |
Revolving Credit Facility
Revolving Credit Facility | 12 Months Ended |
Aug. 31, 2015 | |
Line of Credit Facility [Abstract] | |
Revolving Credit Facility | Revolving Credit Facility The Company maintains a revolving credit facility ("Revolver") with a bank syndicate. The Revolver is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. As most recently amended on June 2, 2015, the terms of the Revolver provide for up to $500 million in borrowings, subject to a borrowing base limitation, as further described below. The maturity date of the Revolver is December 15, 2019 . Certain of the Company’s assets, including substantially all of the producing wells and developed oil and gas leases, have been designated as collateral under the Revolver. The borrowing commitment is subject to adjustment based upon a borrowing base calculation that includes the value of oil and gas reserves. The borrowing base limitation is subject to scheduled redeterminations on a semi-annual basis. In certain events, and at the discretion of the bank syndicate, an unscheduled redetermination could be prepared. During the quarter ended August 31, 2015 , the Company's borrowing base was adjusted to $163 million . Accordingly, as of August 31, 2015 , based on a borrowing base of $163 million and an outstanding principal balance of $78 million , the unused borrowing base available for future borrowing totaled approximately $85 million . The next semi-annual redetermination is scheduled for November 2015 and will be based on the Company's August 31, 2015 reserve report. Interest under the Revolver is payable monthly and accrues at a variable rate, subject to a minimum rate of 2.5% . For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or the London Interbank Offered Rate (“LIBOR”) plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the year ended August 31, 2015 was 2.5% . The Revolver also contains covenants that, among other things, restrict the payment of dividends. In addition, the Revolver generally requires an overall commodity derivative position that covers a rolling 24 months of estimated future production with a minimum position of no less than 45% and a maximum position of no more than 85% of hydrocarbon production as projected in the semi-annual reserve report. Furthermore, the Revolver requires the Company to maintain certain financial and liquidity ratio compliance covenants. Under the requirements, as most recently amended, the Company, on a quarterly basis, must (a) not, at any time, permit its ratio of total funded debt as of such time to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0; and (b) maintain a minimum liquidity, defined as cash and cash equivalents plus the unused availability under the Revolver, of not less than $25 million . As of August 31, 2015 , the most recent compliance date, the Company was in compliance with all loan covenants. |
Commodity Derivative Instrument
Commodity Derivative Instruments | 12 Months Ended |
Aug. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Commodity Derivative Instruments | Commodity Derivative Instruments The Company has entered into commodity derivative instruments, as described below. The Company has utilized swaps, puts or “no premium” collars to reduce the effect of price changes on a portion of its future oil and gas production. A swap requires a payment to the counterparty if the settlement price exceeds the strike price and the same counterparty is required to make a payment if the settlement price is less than the strike price. A collar requires a payment to the counterparty if the settlement price is above the ceiling price and requires the counterparty to make a payment if the settlement price is below the floor price. A put requires the counterparty to make a payment if the settlement price is below the strike price. The objective of the Company’s use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes. The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with four counterparties. Two of the counterparties are lenders in the Company’s credit facility. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from contract settlement of derivatives are recorded in the statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s statements of cash flows. The Company’s valuation estimate takes into consideration the counterparty’s creditworthiness, the Company’s creditworthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. The Company’s commodity derivative contracts as of August 31, 2015 are summarized below: Settlement Period Derivative Instrument Average Volumes (Bbls per month) Average Fixed Price Floor Price Ceiling Price Crude Oil - NYMEX WTI Sep 1, 2015 - Dec 31, 2015 Put 40,000 — $ 50.00 — Sep 1, 2015 - Oct 31, 2015 Put 2,000 — $ 50.00 — Sep 1, 2015 - Dec 31, 2015 Put 10,000 — $ 55.00 — Jan 1, 2016 - Dec 31, 2016 Put 25,000 — $ 50.00 — Jan 1, 2017 - Apr 30, 2017 Put 20,000 — $ 50.00 — May 1, 2017 - Aug 31, 2017 Put 20,000 — $ 55.00 — Settlement Period Derivative Instrument Average Volumes (MMBtu per month) Average Fixed Price Floor Price Ceiling Price Natural Gas - NYMEX Henry Hub Sep 1, 2015 - Dec 31, 2015 Collar 72,000 — $ 4.15 $ 4.49 Jan 1, 2016 - May 31, 2016 Collar 60,000 — $ 4.05 $ 4.54 Jun 1, 2016 - Aug 31, 2016 Collar 60,000 — $ 3.90 $ 4.14 Natural Gas - CIG Rocky Mountain Sep 1, 2015 - Dec 31, 2015 Collar 100,000 — $ 2.20 $ 3.05 Jan 1, 2016 - Dec 31, 2016 Collar 100,000 — $ 2.65 $ 3.10 Jan 1, 2017 - Apr 30, 2017 Collar 100,000 — $ 2.80 $ 3.95 May 1 2017 - Aug 31, 2017 Collar 110,000 — $ 2.50 $ 3.06 Subsequent to August 31, 2015 , the Company added the following position: Settlement Period Derivative Average Volumes Average Floor Price Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2016 - Dec 31, 2016 Put 10,000 — $ 45.00 — Offsetting of Derivative Assets and Liabilities As of August 31, 2015 and 2014 , all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at election of both parties, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to offset these positions in its accompanying balance sheets. The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contract (in thousands): As of August 31, 2015 Underlying Commodity Balance Sheet Location Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Balance Sheet Net Amounts of Assets and Liabilities Presented in the Balance Sheet Commodity Derivative contracts Current assets $ 3,047 $ (150 ) $ 2,897 Commodity Derivative contracts Noncurrent assets $ 1,774 $ (209 ) $ 1,565 Commodity Derivative contracts Current liabilities $ 150 $ (150 ) $ — Commodity Derivative contracts Noncurrent liabilities $ 209 $ (209 ) $ — As of August 31, 2014 Underlying Commodity Balance Sheet Location Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Balance Sheet Net Amounts of Assets and Liabilities Presented in the Balance Sheet Commodity Derivative contracts Current assets $ 903 $ (538 ) $ 365 Commodity Derivative contracts Noncurrent assets $ 718 $ (664 ) $ 54 Commodity Derivative contracts Current liabilities $ 840 $ (538 ) $ 302 Commodity Derivative contracts Noncurrent liabilities $ 971 $ (664 ) $ 307 The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows (in thousands): For the Years Ended August 31, 2015 2014 2013 Realized gain (loss) on commodity derivatives $ 30,466 $ (2,138 ) $ (395 ) Unrealized gain (loss) on commodity derivatives 1,790 2,459 (2,649 ) Total gain (loss) $ 32,256 $ 321 $ (3,044 ) Realized gains and losses include cash received from the monthly settlement of derivative contracts at their scheduled maturity date along with the proceeds from early liquidation of in-the-money derivative contracts. During fiscal year 2015 , the Company liquidated oil derivatives with an average price of $82.79 and covering 372,500 barrels and received cash settlements of approximately $20.5 million . The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended August 31, 2015 2014 2013 Monthly settlement $ 9,957 $ (2,138 ) $ (395 ) Early liquidation 20,509 — — Total realized gain (loss) $ 30,466 $ (2,138 ) $ (395 ) Credit Related Contingent Features As of August 31, 2015 , two of the four counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties. The agreement with the third counterparty, which is not a lender under the credit facility, is unsecured and does not require the posting of collateral. The agreement with the fourth counterparty is subject to an inter-creditor agreement between the counterparty and the Company’s lenders under the credit facility. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Aug. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value Measurements ASC Topic 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company. Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows: • Level 1: Quoted prices available in active markets for identical assets or liabilities; • Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; • Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models. The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The Company’s non-recurring fair value measurements include asset retirement obligations and purchase price allocations for the fair value of assets and liabilities acquired through business combinations. Please refer to Notes 3 and 5 for further discussion of business combinations and asset retirement obligations, respectively. The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and abandonment liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit adjusted discount rates, inflation rates and estimated dates of abandonment. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Note 5 for additional information. The acquisition of a group of assets in a business combination transaction requires fair value estimates for assets acquired and liabilities assumed. The fair value of assets and liabilities acquired through business combinations is calculated using a net discounted-cash flow approach for the producing properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future. Unobservable inputs include estimates of future oil and gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, fair value is determined using market comparables. See Note 3 for additional information. The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of August 31, 2015 and 2014 by level within the fair value hierarchy (in thousands): Fair Value Measurements at August 31, 2015 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 4,462 $ — $ 4,462 Commodity derivative liability $ — $ — $ — $ — Fair Value Measurements at August 31, 2014 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 419 $ — $ 419 Commodity derivative liability $ — $ 609 $ — $ 609 Commodity Derivative Instruments The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At August 31, 2015 , derivative instruments utilized by the Company consist of puts, “no premium” collars and swaps. The crude oil and natural gas derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2. Fair Value of Financial Instruments The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and credit facility borrowings. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company’s credit facility approximated fair value as it bears interest at variable rates over the term of the loan. |
Interest Expense
Interest Expense | 12 Months Ended |
Aug. 31, 2015 | |
Interest and Debt Expense [Abstract] | |
Interest Expense | Interest Expense The components of interest expense are (in thousands): For the Years Ended August 31, 2015 2014 2013 Revolving bank credit facility $ 2,776 $ 986 $ 1,067 Amortization of debt issuance costs 853 448 160 Less, interest capitalized (3,384 ) (1,434 ) (1,130 ) Interest expense, net $ 245 $ — $ 97 |
Shareholders' Equity
Shareholders' Equity | 12 Months Ended |
Aug. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Shareholders' Equity | Shareholders’ Equity The Company's classes of stock are summarized as follows: For the Years Ended August 31, 2015 2014 2013 Preferred stock, shares authorized 10,000,000 10,000,000 10,000,000 Preferred stock, par value $ 0.01 $ 0.01 $ 0.01 Preferred stock, shares issued and outstanding nil nil nil Common stock, shares authorized 200,000,000 200,000,000 100,000,000 Common stock, par value $ 0.001 $ 0.001 $ 0.001 Common stock, shares issued and outstanding 105,099,342 77,999,082 70,587,723 Preferred Stock may be issued in series with such rights and preferences as may be determined by the Board of Directors. Since inception, the Company has not issued any preferred shares. Shares of the Company’s common stock were issued during each of the years ended August 31, 2015 , 2014 , and 2013 , as described further below. Sales of common stock During the years ended August 31, 2015 and 2013 , the Company sold shares of its common stock in public offerings as follows: • In February 2015, the Company completed the sale of common stock in an underwritten public offering led by Seaport Global Securities LLC. • In June 2013, the Company completed the sale of common stock in an underwritten public offering led by Johnson Rice LLC. Certain details of each transaction are shown in the following table. Net proceeds represent amounts received by the Company after deductions for underwriting discounts, commissions and expenses of the offering. For the Years Ended August 31, 2015 2014 2013 Number of common shares sold 18,613,952 — 13,225,000 Offering price per common share $ 10.75 $ — $ 6.25 Net proceeds (in thousands) $ 190,845 $ — $ 78,243 Common stock issued for acquisition of mineral property interests During the fiscal years presented, the Company issued shares of common stock in exchange for mineral property interests. The value of each transaction was determined using the market price of the Company’s common stock on the date of each transaction. For the Years Ended August 31, 2015 2014 2013 Number of common shares issued for mineral property leases 995,672 357,901 687,122 Number of common shares issued for acquisitions 4,648,136 872,483 3,128,422 Total common shares issued 5,643,808 1,230,384 3,815,544 Average price per common share $ 10.67 $ 9.09 $ 4.37 Aggregate value of shares issues (in thousands) $ 60,221 $ 11,184 $ 16,684 Common stock warrants The Company previously issued warrants to purchase common stock, many of which remained outstanding at the beginning of the Company's 2015 fiscal year. The relevant terms of the warrants are described in the following paragraphs. Series A – During the year ended August 31, 2009, the Company issued 4,098,000 Series A warrants, each of which was immediately exercisable. Each Series A warrant entitled the holder to purchase one share of common stock for $6.00 . All of the Series A warrants expired on December 31, 2012. Series B – During the year ended August 31, 2009, the Company issued 1,000,000 Series B warrants, each of which was immediately exercisable. Each Series B warrant entitled the holder to purchase one share of common stock for $10.00 . All of the Series B warrants expired on December 31, 2012. Series C – During the year ended August 31, 2010, the Company issued 9,000,000 Series C warrants in connection with a unit offering. Each unit included one convertible promissory note with a face value of $100,000 and 50,000 Series C warrants. Each Series C warrant entitled the holder to purchase one share of common stock for $6.00 and expired on December 31, 2014, if not previously exercised. In the three year period ended August 31, 2015 , the following Series C warrants were exercised: 2,561,415 during fiscal 2015 , 5,938,585 during fiscal 2014 , and 500,000 during fiscal 2013 . Series D – During the year ended August 31, 2010, the Company issued 1,125,000 Series D warrants to the placement agent for the Series C unit offering. Each Series D warrant entitled the holder to purchase one share of common stock for $1.60 , and contained a net settlement provision that provided for exercise of the warrants on a cashless basis. The Series D warrants expired, if not previously exercised, on December 31, 2014. In the three year period ended August 31, 2015, the following warrants were exercised: 1,058 during fiscal 2015 , 140,744 during fiscal 2014 , and 627,799 during fiscal 2013 . Sales Agent Warrants – During the year ended August 31, 2009, the Company issued 31,733 warrants to the sales agent for an equity offering (the "Sales Agent Warrants"). Each Sales Agent Warrant entitled the holder to purchase two shares of common stock for $1.80 per share. All of the Sales Agent Warrants were exercised during the year ended August 31, 2013. Investor Relations Warrants – During the year ended August 31, 2012, the Company issued 100,000 warrants to a firm providing investor relations services (the "Investor Relations Warrants"). Each Investor Relations Warrant entitled the holder to purchase one share of common stock for $2.69 , and contained a net settlement provision that provided for exercise of the warrants on a cashless basis. The warrants became exercisable in equal quarterly installments over a one year period. During the year ended August 31, 2013, warrants to purchase 50,000 shares became exercisable and warrants to purchase 50,000 shares were forfeited due to early termination of the agreement with the firm. During each of the three years ended August 31, 2015 , the following Investor Relations Warrants were exercised: nil during fiscal 2015 , 25,000 during fiscal 2014 , and 25,000 during fiscal 2013 . The following table summarizes activity for common stock warrants for the fiscal years presented: Number of Shares Issuable Upon Warrant Exercise Weighted-Average Exercise Price Per Share Outstanding, August 31, 2012 15,031,067 $ 6.02 Exercised 1,216,265 $ 3.44 Forfeited/Expired 5,148,000 $ 6.74 Outstanding, August 31, 2013 8,666,802 $ 5.92 Exercised 6,104,329 $ 5.88 Forfeited / Expired — $ — Outstanding, August 31, 2014 2,562,473 $ 6.00 Exercised 2,562,473 $ 6.00 Forfeited / Expired — $ — Outstanding, August 31, 2015 — $ — |
Stock-Based Compensation
Stock-Based Compensation | 12 Months Ended |
Aug. 31, 2015 | |
Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |
Stock-Based Compensation | Stock-Based Compensation In addition to cash compensation, the Company may compensate certain service providers, including employees, directors, consultants, and other advisors, with equity based compensation in the form of stock options, stock bonus shares, and warrants. The Company records an expense related to equity compensation by pro-rating the estimated grant date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the “vesting phase”). The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock. Indirect valuations are calculated using the Black-Scholes-Merton option pricing model. For the periods presented, all stock-based compensation expense was classified as a component within general and administrative expense in the Company's statements of operations. The amount of stock-based compensation expense is as follows (in thousands): For the Years Ended August 31, 2015 2014 2013 Stock options $ 4,741 $ 1,767 $ 1,039 Stock bonus shares 2,950 1,201 277 Investor relations warrants — — 46 $ 7,691 $ 2,968 $ 1,362 General Description of Stock Option and Other Stock Award Plans The Company has three stock award plans: (i) a 2011 non-qualified stock option plan, (ii) a 2011 incentive stock option plan, and (iii) a 2011 stock bonus plan. Shareholders authorized the issuance of up to 5 million shares under the non-qualified stock option plan, and up to 2 million shares under each of the incentive stock option and stock bonus plans. Each plan authorizes the issuance of shares of the Company's common stock to persons that exercise options granted pursuant to the plan. Employees, directors, officers, consultants and advisors are eligible to receive such awards, provided that bona fide services be rendered by such consultants or advisors and such services must not be in connection with promoting the Company's stock or the sale of securities in a capital-raising transaction. The option exercise price is determined by the Board of Directors, based on the quoted closing market price of Company's common stock at the time of grant. As of August 31, 2015 , there were 384,500 shares available for future issuance under the non-qualified plan, 2,000,000 shares available for issuance under the incentive stock option plan, and 723,937 shares available for future issuance under the stock bonus plan. Stock options under the non-qualified stock option plan During the respective fiscal years, the Company granted the following non-qualified stock options: For the Years Ended August 31, 2015 2014 2013 Number of options to purchase common shares 2,377,500 433,000 1,025,000 Weighted-average exercise price $ 11.55 $ 10.37 $ 6.05 Term (in years) 10 years 10 years 10 years Vesting Period (in years) 3-5 years 5 years 3-5 years Fair Value (in thousands) $ 13,266 $ 3,009 $ 4,179 The assumptions used in valuing stock options granted during each of the fiscal years presented were as follows: For the Years Ended August 31, 2015 2014 2013 Expected term 6.5 years 6.7 years 6.2 years Expected volatility 47 % 73 % 77 % Risk free rate 1.4 - 2.0% 1.8 - 2.3% 0.9 - 2.1% Expected dividend yield 0.0 % 0.0 % 0.0 % Average forfeiture rate 3.5 % 0.0 % 0.0 % The following table summarizes activity for stock options for the fiscal years presented: Number of Weighted-Average Weighted-Average Aggregate Intrinsic Value Outstanding, August 31, 2012 4,915,000 $ 5.09 2.2 years $ 3,656 Granted 1,025,000 $ 6.05 Exercised (2,120,000 ) $ 1.10 15,690 Forfeited (2,000,000 ) $ 10.00 Outstanding, August 31, 2013 1,820,000 $ 4.88 8.7 years 8,160 Granted 433,000 $ 10.37 Exercised (61,000 ) $ 3.71 481 Expired (25,000 ) $ 10.32 Outstanding, August 31, 2014 2,167,000 $ 5.94 8.0 years 16,287 Granted 2,377,500 $ 11.55 Exercised (258,000 ) $ 3.81 2,103 Forfeited (110,000 ) $ 4.97 Outstanding, August 31, 2015 4,176,500 $ 9.29 8.6 years $ 8,187 Outstanding, Exercisable at August 31, 2015 1,330,600 $ 7.03 7.5 years $ 5,211 Outstanding, Vested and expected to vest at August 31, 2015 4,027,604 $ 9.21 8.6 years $ 8,180 The following table summarizes information about issued and outstanding stock options as of August 31, 2015 : Outstanding Options Exercisable Options Range of Exercise Prices Options Weighted-Average Remaining Contractual Life Weighted-Average Exercise Price per Share Options Weighted-Average Exercise Price per Share Under $5.00 679,000 6.1 years $ 3.53 463,000 $3.52 $5.00 - $6.99 637,000 7.5 years 6.54 412,000 6.59 $7.00 - $10.99 563,000 8.6 years 9.65 89,600 8.97 $11.00 - $13.46 2,297,500 9.6 years 11.66 366,000 11.50 Total 4,176,500 8.6 years $ 9.29 1,330,600 $7.03 The estimated unrecognized compensation cost from unvested stock options as of August 31, 2015 , which will be recognized ratably over the remaining vesting phase, is as follows: Unvested Options at August 31, 2015 Unrecognized compensation expense (in thousands) $ 12,733 Remaining vesting phase 3.6 years Restricted stock awards under the stock bonus plan The Company grants shares of restricted stock to directors, eligible employees and officers as a part of its equity incentive plan. Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each share of restricted stock represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically vest in equal increments over three to five years . Shares of restricted stock are valued at the closing price of the Company’s common stock on the grant date and are recognized as general and administrative expense over the vesting period of the award. The following table summarizes activity for restricted stock awards for the fiscal years presented: Number of Weighted-Average Non-vested, August 31, 2012 13,750 $ 3.06 Granted 109,096 $ 6.41 Vested (76,179 ) $ 5.60 Forfeited — $ — Non-vested, August 31, 2013 46,667 $ 6.75 Granted 343,780 $ 11.34 Vested (97,114 ) $ 11.38 Forfeited — $ — Non-vested, August 31, 2014 293,333 $ 10.60 Granted 547,699 $ 11.17 Vested (208,532 ) $ 11.09 Forfeited — $ — Non-vested, August 31, 2015 632,500 $ 10.93 The estimated unrecognized compensation cost from unvested restricted stock awards as of August 31, 2015 , which will be recognized ratably over the remaining vesting phase, is as follows: Unvested awards as of August 31, 2015 Unrecognized compensation expense (in thousands) $ 6,720 Remaining vesting phase 2.2 years |
Income Taxes
Income Taxes | 12 Months Ended |
Aug. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes The income tax provision is comprised of the following (in thousands): As of August 31, 2015 2014 2013 Current: Federal $ (4 ) $ 4 $ — State (111 ) 111 — Total current income tax expense (benefit) $ (115 ) $ 115 $ — Deferred: Federal $ 10,820 $ 13,748 $ 6,367 State 972 1,151 503 Total deferred income tax expense $ 11,792 $ 14,899 $ 6,870 Income tax provision $ 11,677 $ 15,014 $ 6,870 A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): As of August 31, 2015 2014 2013 Federal income tax at statutory rate $ 10,105 $ 14,915 $ 5,594 State income taxes, net of federal tax 908 1,341 503 Statutory depletion (451 ) (1,266 ) (929 ) Stock-based compensation 92 — 1,911 Nondeductible compensation 850 125 — Other 173 (101 ) (209 ) Income tax provision $ 11,677 $ 15,014 $ 6,870 Effective rate expressed as a percentage 39 % 34 % 42 % In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the fiscal year ends is presented in the following table (in thousands): As of August 31, 2015 2014 Deferred tax assets: Net operating loss carryforward $ 3,387 $ 8,589 Stock-based compensation 2,788 1,115 Statutory depletion 2,652 2,194 Unrealized loss on commodity derivative — 70 Other 192 4 Gross deferred tax assets $ 9,019 $ 11,972 Deferred tax liabilities: Basis of oil and gas properties 18,433 33,409 Unrealized gain on commodity derivative 593 — Gross deferred tax liabilities 19,026 33,409 Deferred tax liability, net $ 10,007 $ 21,437 At August 31, 2015 , the Company has a net operating loss carryforward for federal and state tax purposes of approximately $21.3 million that could be utilized to offset taxable income of future years. For financial reporting purposes, the Company has net operating losses of approximately $9.2 million for federal and state. The difference of $12.1 million relates to tax deductions for compensation expense for financial reporting purposes for which the benefit will not be recognized until the related deductions reduce taxes payable. The net operating loss carryovers may be carried back two years and forward twenty years from the year the net operating loss was generated. Substantially all of the carryforward will commence expiring in 2031 , 2032, and 2033 . The realization of the deferred tax assets related to the NOL carryforwards is dependent on the Company’s ability to generate sufficient future taxable income within the applicable carryforward periods. As of August 31, 2015 , the Company believes it will be able to generate sufficient future taxable income within the carryforward periods and, accordingly, believes that it is more likely than not that its net deferred income tax assets will be fully realized. The ability of the Company to utilize its NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards. The Company completed a study of the impact of the Code Section 382 limitation on future payments and determined that the statutory provisions were unlikely to limit the Company's ability to realize future tax benefits. As of August 31, 2015 , the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. Most of the Company's tax returns filed since August 31, 2011 are still subject to examination by tax authorities. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Aug. 31, 2015 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Whenever the Company engages in transactions with its officers, directors, or other related parties, the terms of the transaction are reviewed by the disinterested directors. All transactions must be on terms no less favorable to the Company than similar transactions with unrelated parties. Lease Agreement: The Company leases its Platteville facilities under a lease agreement with HS Land & Cattle, LLC (“HSLC”). HSLC is controlled by Ed Holloway and William Scaff, Jr., the Company’s co-Chief Executive Officers. The current lease, dated June 30, 2014, is currently on a month-to-month basis. Historically, the lease has been renewed annually. Under this agreement, the Company incurred the following expenses to HSLC for the fiscal years presented (in thousands): For the Years Ended August 31, 2015 2014 2013 Rent expense $ 180 $ 180 $ 130 Mineral Leasing Program: During 2010, the Company initiated a program to acquire mineral interests in several Colorado and Nebraska counties that are considered the eastern portion of the D-J Basin. George Seward, a member of the Company’s board of directors, agreed to lead that program. The Company agreed to compensate certain persons, including Mr. Seward, to assist the Company with the acquisitions at a specific rate per qualifying net mineral acre. The compensation is paid in the form of restricted shares of the Company’s common stock, as follows: For the Years Ended August 31, 2015 2014 2013 Shares of restricted common stock — 15,883 31,454 Value of common stock (in thousands) $ — $ 106 $ 105 Mineral Leases Acquired from Director : Mr. Seward owns mineral interests in several Colorado and Nebraska counties. He agreed to lease his interests to the Company in exchange for restricted shares of common stock. The following table discloses the acquisition of mineral leases from Mr. Seward during each of the fiscal years presented: For the Years Ended August 31, 2015 2014 2013 Mineral acres leased — 4,844 2,263 Shares of restricted common stock — 40,435 22,202 Value of common stock (in thousands) $ — $ 313 $ 91 Revenue Distribution Processing: Effective January 1, 2012, the Company commenced processing revenue distribution payments to all persons that own a mineral interest in wells that it operates. Payments to mineral interest owners included payments to entities controlled by three of the Company’s directors, Ed Holloway, William Scaff Jr, and George Seward. The following table summarizes the royalty payments made to directors or their affiliates for the fiscal years presented (in thousands): For the Years Ended August 31, 2015 2014 2013 Total royalty payments $ 209 $ 292 $ 304 |
Other Commitments and Contingen
Other Commitments and Contingencies | 12 Months Ended |
Aug. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Other Commitments and Contingencies | Other Commitments and Contingencies Drilling rig As of August 31, 2015 , the Company was using one drilling rig under a contract with Ensign United States Drilling, Inc. The contract for this rig terminates on December 31, 2015. As of August 31, 2015, the remaining minimum payments due under the contract are approximately $2.3 million . Volume Commitments During 2015, the Company entered into agreements that require us to deliver minimum amounts of crude oil to a third party marketer and to two counterparties that transport crude oil via pipelines. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next five years, as follows: Year ending August 31, (in MBbls/year) 2016 2,213 2017 4,072 2018 4,072 2019 4,072 2020 4,072 Thereafter 1,860 Total 20,361 Additionally, we have committed to deliver 7,500 Bbls of oil per day for the remainder of the 2015 calendar year to a third party refiner. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements or we may have to purchase oil from third parties to fulfill our delivery obligations. Office leases The Company leases its Platteville offices and other facilities from a related party, as described in Note 13 . In addition, subsequent to August 31, 2015 , the Company moved its principal offices to leased facilities in Denver. The Denver office lease requires monthly payments of approximately $30,000 and terminates in October 2016 . Litigation From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current matters of contention are reasonably likely to have a material adverse impact on its business, financial position, results of operations or cash flows. |
Supplemental Schedule of Inform
Supplemental Schedule of Information to the Statements of Cash Flows | 12 Months Ended |
Aug. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Supplemental Schedule of Information to the Statements of Cash Flows | Supplemental Schedule of Information to the Statements of Cash Flows The following table supplements the cash flow information presented in the financial statements for the fiscal years presented (in thousands): For the Years Ended August 31, Supplemental cash flow information: 2015 2014 2013 Interest paid $ 2,817 $ 989 $ 995 Income taxes paid 202 — — Non-cash investing and financing activities: Accrued well costs $ 33,071 $ 71,849 $ 25,491 Assets acquired in exchange for common stock 60,221 11,184 16,684 Asset retirement costs and obligations 7,051 1,610 1,578 |
Unaudited Oil and Gas Reserves
Unaudited Oil and Gas Reserves Information | 12 Months Ended |
Aug. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Unaudited Oil and Gas Reserves Information | Unaudited Oil and Gas Reserves Information Oil and Natural Gas Reserve Information: Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made). Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved oil and natural gas reserve information as of the fiscal year ends presented, and the related discounted future net cash flows before income taxes, are based on estimates prepared by Ryder Scott Company LP. Reserve information for the properties was prepared in accordance with guidelines established by the SEC. The reserve estimates prepared as of each of the fiscal year ends presented were prepared in accordance with “Modernization of Oil and Gas Reporting” published by the SEC. The guidance included updated definitions of proved developed and proved undeveloped oil and gas reserves, oil and gas producing activities and other terms. Proved oil and gas reserves were calculated based on the prices for oil and gas during the twelve-month period before the respective reporting date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period, rather than the year-end spot prices, which had been used in prior years. This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking. The guidance broadened the types of technologies that may be used to establish reserve estimates. The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and gas reserve quantities and changes therein for each of the fiscal years presented: Oil (MBbl) Gas (MMcf) MBOE Balance, August 31, 2012 5,086 33,446 10,660 Revision of previous estimates (194 ) (2,924 ) (681 ) Purchase of reserves in place 1,000 7,361 2,228 Extensions, discoveries, and other additions 1,576 4,915 2,395 Sale of reserves in place — — — Production (421 ) (2,108 ) (773 ) Balance, August 31, 2013 7,047 40,690 13,829 Revision of previous estimates 83 3,047 591 Purchase of reserves in place 1,028 5,956 2,021 Extensions, discoveries, and other additions 9,142 49,289 17,357 Sale of reserves in place (35 ) (56 ) (44 ) Production (941 ) (3,747 ) (1,566 ) Balance, August 31, 2014 16,324 95,179 32,188 Revision of previous estimates (1,699 ) (4,889 ) (2,513 ) Purchase of reserves in place 4,201 21,957 7,860 Extensions, discoveries, and other additions 11,465 73,392 23,696 Sale of reserves in place (629 ) (4,337 ) (1,352 ) Production (1,970 ) (7,344 ) (3,194 ) Balance, August 31, 2015 27,692 173,958 56,685 Proved developed and undeveloped reserves: Developed at August 31, 2013 4,659 25,866 8,970 Undeveloped at August 31, 2013 2,388 14,824 4,859 Balance, August 31, 2013 7,047 40,690 13,829 Developed at August 31, 2014 6,616 38,162 12,977 Undeveloped at August 31, 2014 9,708 57,017 19,211 Balance, August 31, 2014 16,324 95,179 32,188 Developed at August 31, 2015 7,393 46,026 15,064 Undeveloped at August 31, 2015 20,299 127,932 41,621 Balance, August 31, 2015 27,692 173,958 56,685 Notable changes in proved reserves for the year ended August 31, 2015 included: • Purchases of reserves in place . In 2015 , purchases of reserves in place of 7,860 MBO E were attributable to the acquisition of proved reserves from Bayswater. Please see Note 3 for further information. • Revision of previous estimates. In 2015 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 2,513 MBOE. As the Company continued to revise its drilling plans toward horizontal drilling, the vertical proved undeveloped and vertical developed non-producing locations were removed from its development plan. • Extensions and discoveries. In 2015 , total extensions and discoveries of 23,696 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The Company drilled 67 successful exploratory wells. In addition, successful drilling by other operators in adjacent acreage allowed us to increase our proved undeveloped locations. Notable changes in proved reserves for the year ended August 31, 2014 included: • Purchases of reserves in place. In 2014 , purchases of reserves in place of 2,021 MBOE were attributable to the acquisition of producing oil and gas wells and undeveloped acreage from Trilogy Resources, LLC and Apollo Operating, LLC. Please see Note 3 for further information. • Revision of previous estimates. In 2014 , revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 591 MBOE. The prices for the 2014 oil and gas reserves are based on the 12 month arithmetic average for the first of month prices as adjusted for our differentials from September 1, 2013 through August 31, 2014 . The 2014 crude oil price of $89.48 per barrel (West Texas Intermediate Cushing) was $3.08 higher than the 2013 crude oil price of $86.40 per barrel. The 2014 natural gas price of $5.03 per Mcf (Henry Hub) was $0.63 higher than the 2013 price of $4.40 per Mcf. • Extensions and discoveries. In 2014 , total extensions and discoveries of 17,357 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves. Notable changes in proved reserves for the year ended August 31, 2013 included: • Purchases of reserves in place. In 2013 , purchases of reserves in place of 2,228 MBOE were attributable to the acquisition of 36 producing oil and gas wells and undeveloped acreage from Orr Energy, LLC. • Revision of previous estimates. In 2013 , revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 681 MBOE as the Company’s drilling schedule was adjusted to reflect the elimination of previously planned vertical drilling locations as the development focus shifted from vertical to horizontal drilling. • Extensions and discoveries. In 2013 , total extensions and discoveries of 2,395 MBOE were primarily attributable to successful drilling in the Wattenberg Field. The new producing wells in this area and their adjacent proved undeveloped locations added during the year increased the Company’s proved reserves. Standardized Measure of Discounted Future Net Cash Flows: The following analysis is a standardized measure of future net cash flows and changes therein related to estimated proved reserves. Future oil and gas sales have been computed by applying average prices of oil and gas during each of the fiscal years presented. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs. The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs. Future income tax expenses were calculated by applying year-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and gas producing activities. All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and gas reserves. Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas, and changes in governmental regulations or taxation. The following table sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by the SEC (in thousands): For the Years Ended August 31, 2015 2014 2013 Future cash inflow $ 2,046,615 $ 1,839,987 $ 749,030 Future production costs (653,009 ) (395,019 ) (146,352 ) Future development costs (510,720 ) (412,517 ) (108,290 ) Future income tax expense (144,399 ) (252,925 ) (113,545 ) Future net cash flows 738,487 779,526 380,843 10% annual discount for estimated timing of cash flows (372,658 ) (376,827 ) (199,111 ) Standardized measure of discounted future net cash flows $ 365,829 $ 402,699 $ 181,732 There have been significant fluctuations in the posted prices of oil and natural gas during the last three years. Prices actually received from purchasers of the Company’s oil and gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices. The following table presents the prices used to prepare the reserve estimates, based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials: Oil (Bbl) Gas (Mcf) August 31, 2013 (Average) $ 86.40 $ 4.40 August 31, 2014 (Average) $ 89.48 $ 5.03 August 31, 2015 (Average) $ 53.27 $ 3.28 The prices for the 2015 oil and gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from September 1, 2014 through August 31, 2015 . The 2015 crude oil price of $53.27 per barrel (West Texas Intermediate Cushing) was $36.21 lower than the 2014 crude oil price of $89.48 per barrel. The 2015 natural gas price of $3.28 per Mcf (Henry Hub) was $1.75 lower than the 2014 price of $5.03 per Mcf. Changes in the Standardized Measure of Discounted Future Net Cash Flows: The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands): For the Years Ended August 31, 2015 2014 2013 Standardized measure, beginning of year $ 402,699 $ 181,732 $ 102,505 Sale and transfers, net of production costs (98,486 ) (86,808 ) (38,569 ) Net changes in prices and production costs (233,051 ) 15,828 (4,550 ) Extensions, discoveries, and improved recovery 173,918 300,087 70,191 Changes in estimated future development costs 10,002 (20,817 ) (6,006 ) Development costs incurred during the period 4,957 15,000 5,106 Revision of quantity estimates (38,340 ) 4,589 (14,214 ) Accretion of discount 57,629 23,612 35,103 Net change in income taxes 58,547 (76,616 ) (7,850 ) Divestitures of reserves (19,234 ) (925 ) — Purchase of reserves in place 56,795 47,017 40,016 Changes in timing and other (9,607 ) — — Standardized measure, end of year $ 365,829 $ 402,699 $ 181,732 |
Unaudited Quarterly Financial D
Unaudited Quarterly Financial Data | 12 Months Ended |
Aug. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Unaudited Quarterly Financial Data | Unaudited Quarterly Financial Data The Company’s unaudited quarterly financial information for the years ended August 31, 2015 and 2014 is as follows (in thousands, except share data): For the Year Ended August 31, 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 42,538 $ 23,713 $ 26,033 $ 32,559 Expenses 27,783 25,417 29,102 44,919 Operating income (loss) 14,755 (1,704 ) (3,069 ) (12,360 ) Other income (expense) 18,140 9,563 (1,245 ) 5,639 Income (loss) before income taxes 32,895 7,859 (4,314 ) (6,721 ) Income tax provision (benefit) 11,744 3,207 (1,833 ) (1,441 ) Net income (loss) $ 21,151 $ 4,652 $ (2,481 ) $ (5,280 ) Net income (loss) per common share: (1) Basic $ 0.27 $ 0.05 $ (0.02 ) $ (0.05 ) Diluted $ 0.26 $ 0.05 $ (0.02 ) $ (0.05 ) Weighted-average shares outstanding: Basic 79,008,719 89,903,288 104,234,519 105,084,651 Diluted 80,141,152 90,636,107 (2) (2) For the Year Ended August 31, 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 19,266 $ 23,028 $ 25,672 $ 36,253 Expenses 12,048 13,550 14,413 20,744 Operating income 7,218 9,478 11,259 15,509 Other income (expense) 2,269 (1,979 ) (983 ) 1,096 Income before income taxes 9,487 7,499 10,276 16,605 Income tax provision 3,387 2,338 3,116 6,173 Net income $ 6,100 $ 5,161 $ 7,160 $ 10,432 Net income per common share: (1) Basic $ 0.08 $ 0.07 $ 0.09 $ 0.13 Diluted $ 0.08 $ 0.07 $ 0.09 $ 0.13 Weighted-average shares outstanding: Basic 73,674,865 76,203,938 77,176,420 77,771,916 Diluted 76,044,605 77,990,416 79,008,619 79,698,720 1 The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year. 2 Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive. |
Subsequent Events
Subsequent Events | 12 Months Ended |
Aug. 31, 2015 | |
Subsequent Events [Abstract] | |
Subsequent Events | Subsequent Events Kauffman Acquisition On September 14, 2015, the Company entered into an agreement with K.P. Kauffman Company, Inc. ("Kauffman") to acquire from Kauffman approximately 4,300 net acres of oil and gas leasehold interests and related assets in the D-J Basin of Colorado for $35 million in cash and approximately 4.4 million restricted shares of the Company's common stock, in each case subject to certain customary adjustments. The agreement contains provisions relating to title and environmental due diligence, purchase price adjustments, indemnification, representations and covenants typical for this type of transaction. Current net production associated with the purchased assets is approximately 1,200 barrels of oil equivalent per day (BOED). The transaction has an effective date of September 1, 2015 and is expected to close on or before October 30, 2015 . |
Organization and Summary of S26
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Aug. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation: The Company has adopted August 31st as the end of its fiscal year. The Company does not utilize any special purpose entities. The Company operates in one business segment and all of its operations are located in the United States of America. At the directive of the Securities and Exchange Commission to use “plain English” in public filings, the Company will use such terms as “we,” “our,” “us” or “the Company” in place of Synergy Resources Corporation. When such terms are used in this manner throughout this document, they are in reference only to the corporation, Synergy Resources Corporation, and are not used in reference to the Board of Directors, corporate officers, management, or any individual employee or group of employees. The Company prepares its financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). |
Use of Estimates | Use of Estimates: The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and gas reserves and goodwill, business combinations, derivatives, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically and the effects of revisions are reflected in the financial statements in the period it is determined to be necessary. Actual results could differ from these estimates. |
Cash and Cash Equivalents | Cash and Cash Equivalents: The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents. |
Short-Term Investments | Short-Term Investments: As part of its cash management strategies, the Company invests in short-term interest bearing deposits such as certificates of deposits with maturities of less than one year. |
Inventory | Inventory: Inventories consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market. |
Oil and Gas Properties | Oil and Gas Properties: The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include land acquisition costs, geological and geophysical expense, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or abandonment of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and gas reserves. Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved petroleum reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is the impairment test prescribed by SEC regulations. The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties. The present value of estimated future net revenues is computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves; the result of which is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued on the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depreciation, depletion, and amortization, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period, unless prices are defined by contractual arrangements. Prices are adjusted for basis or location differentials and are held constant for the productive life of each well. |
Oil and Gas Reserves | Oil and Gas Reserves: Oil and gas reserves represent theoretical, estimated quantities of crude oil and natural gas which geological and engineering data estimate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and gas reserves and their values, including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves. The determination of depletion and amortization expenses, as well as the ceiling test calculation related to the recorded value of the Company’s oil and natural gas properties, is highly dependent on estimates of proved oil and natural gas reserves. |
Capitalized Interest | Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisition of mineral interests and exploration and development projects that are not subject to current amortization. Interest is capitalized during the period that activities are in progress to bring the projects to their intended use. See Note 9 for additional information. |
Capitalized Overhead | Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities. Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands). For the Years Ended August 31, 2015 2014 2013 Capitalized overhead $ 2,049 $ 1,230 $ 637 |
Well Costs Payable | Well Costs Payable: The cost of wells in progress are recorded as incurred, generally based upon invoiced amounts or joint interest billings (“JIB”). For those instances in which an invoice or JIB is not received on a timely basis, estimated costs are accrued to oil and gas properties, generally based on the authorization for expenditure. |
Other Property and Equipment | Other Property and Equipment: Support equipment (including such items as vehicles, well servicing equipment, and office furniture and equipment) is stated at the lower of cost or market. Depreciation of support equipment is computed using primarily the straight-line method over periods ranging from five to seven years. |
Asset Retirement Obligations | Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently removed from service. Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to remove the asset from service, and inflation factors. The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit adjusted risk-free interest rate. Estimates are periodically reviewed and adjusted to reflect changes. The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made. This is typically when a well is completed or an asset is placed in service. When the ARO is initially recorded, the Company capitalizes the cost (asset retirement cost or “ARC”) by increasing the carrying value of the related asset. ARCs related to wells are capitalized to the full cost pool and subject to depletion. Over time, the liability increases for the change in its present value (accretion of ARO), while the net capitalized cost decreases over the useful life of the asset, as depletion expense is recognized. In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment. |
Business Combinations | Business Combinations: The Company accounts for its acquisitions using the acquisition method under ASC 805, Business Combinations. Under the acquisition method, assets acquired and liabilities assumed are recognized and measured at their fair values. The use of fair value accounting requires the use of significant judgment since some transaction components do not have fair values that are readily determinable. The excess, if any, of the purchase price over the net fair value amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. Conversely, if the fair value of assets acquired exceeds the purchase price, including liabilities assumed, the excess is immediately recognized in earnings as a bargain purchase gain. |
Goodwill | Goodwill: Goodwill results from business combinations and represents the excess of the purchase price over the estimated fair value of the net assets acquired in a business combination. Goodwill has an indefinite useful life and is not amortized, but rather is tested by the Company for impairment annually, or more often if events or circumstances indicate that the fair value of a reporting unit may have been reduced below its carrying value. If the Company’s qualitative analysis indicates that it is more likely than not that the fair value of the reporting unit is less than its carrying value, the Company then performs a quantitative impairment test. If the carrying value of the reporting unit exceeds its fair value, goodwill is written down to its implied fair value with an offsetting charge to earnings. During the year ended August 31, 2015 , the Company did not recognize an impairment to goodwill. |
Oil and Gas Sales | Oil and Gas Sales: The Company derives revenue primarily from the sale of crude oil and natural gas produced on its properties. Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests. Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the oil is transferred to the purchaser. Payment is generally received between thirty and ninety days after the date of production. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement. |
Major Customers | Major Customers: The Company sells production to a small number of customers, as is customary in the industry. As a result, during the fiscal years ended August 31, 2015 , 2014 and 2013 , certain of the Company’s customers represented 10% or more of its oil and gas revenue (“major customers”). For the fiscal year ended August 31, 2015 , the Company had two major customers, which represented 65% and 11% of its revenue during the period. For the fiscal year ended August 31, 2014 , the Company had two major customers, which represented 54% and 13% of its revenue during the period. For the fiscal year ended August 31, 2013 , the Company had two major customers, which represented 50% and 15% of its revenue during the period. Based on the current demand for oil and natural gas, the availability of other buyers, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that its oil and gas production can be sold in the market in the event that it is not sold to the Company’s existing customers. However, in some circumstances, a change in customers may entail significant transition costs and/or shutting in or curtailing production for weeks or even months during the transition to a new customer. Accounts receivable consist primarily of trade receivables from oil and gas sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners. Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table: As of August 31, 2015 2014 2013 Company A 30% 37% 24% Company B * * 23% Company C * * 12% * less than 10% The Company operates exclusively within the United States of America and, except for cash and short-term investments, all of the Company’s assets are employed in and all of its revenues are derived from the oil and gas industry. |
Lease Operating Expenses | Lease Operating Expenses: Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred. Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities, property taxes and insurance applicable to proved properties and wells and related equipment and facilities. |
Stock-Based Compensation | Stock-Based Compensation: The Company recognizes all equity-based compensation as stock-based compensation expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model. For restricted stock awards, fair value is the closing stock price for the Company's common stock on the grant date. The expense is recognized over the vesting period of the grant. See Note 11 for additional information. |
Income Tax | Income Tax: Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. No significant uncertain tax positions were identified as of any date on or before August 31, 2015 . The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense. As of August 31, 2015 , the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 12 for further information. |
Financial Instruments | Financial Instruments : Financial instruments, whether measured on a recurring or non-recurring basis, are recorded at fair value. A fair value hierarchy, established by the Financial Accounting Standards Board (“FASB”), prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). |
Commodity Derivative Instruments | Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or “no premium” collars to reduce the effect of price changes on a portion of its future oil and gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative line on the statement of operations. The Company values its derivative instruments by obtaining independent market quotes, as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors, as well as other relevant economic measures. The Company compares the valuations calculated by it to valuations provided by the counterparties to assess the reasonableness of each valuation. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, please refer to Note 7 . |
Earnings Per Share Amounts | Earnings Per Share Amounts: Basic earnings per share includes no dilution and is computed by dividing net income by the weighted-average number of shares outstanding during the period. Diluted earnings per share reflect the potential dilution of securities that could share in the earnings of the Company. The number of potential shares outstanding relating to stock options, non-vested restricted stock, and warrants is computed using the treasury stock method. Potentially dilutive securities outstanding are not included in the calculation when such securities would have an anti-dilutive effect on earnings per share. The following table sets forth the share calculation of diluted earnings per share: For the Years Ended August 31, 2015 2014 2013 Weighted-average shares outstanding - basic 94,628,665 76,214,737 57,089,362 Potentially dilutive common shares from: Stock options 672,493 479,222 1,881,682 Restricted stock 18,111 — — Warrants — 1,114,095 117,717 Weighted-average shares outstanding - diluted 95,319,269 77,808,054 59,088,761 The following potentially dilutive securities outstanding for the fiscal years presented were not included in the respective earnings per share calculation above, as such securities had an anti-dilutive effect on earnings per share: For the Years Ended August 31, 2015 2014 2013 Potentially dilutive common shares from: Stock options 2,785,500 533,000 670,000 Restricted stock 145,000 — — Warrants — — 8,500,000 Total 2,930,500 533,000 9,170,000 |
Recent Accounting Pronouncements | Recent Accounting Pronouncements: We evaluate the pronouncements of various authoritative accounting organizations to determine the impact of new accounting pronouncements on us. In January 2015, the FASB issued Accounting Standards Update 2015-01, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items” (“ASU 2015-01”), which eliminates from US GAAP the concept of extraordinary items, while retaining certain presentation and disclosure guidance for items that are unusual in nature or occur infrequently. The standard is effective prospectively for fiscal years and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted provided the guidance is applied from the beginning of the fiscal year of adoption. Adoption of ASU 2015-01 is not expected to have a material effect on our financial position, results of operations, or cash flows. In November 2014, the FASB issued Accounting Standards Update 2014-16, “Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity” (“ASU 2014-16”), which clarifies how to evaluate the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, ASU 2014-16 requires that an entity consider all relevant terms and features in evaluating the nature of the host contract and clarifies that the nature of the host contract depends upon the economic characteristics and the risks of the entire hybrid financial instrument. An entity should assess the substance of the relevant terms and features, including the relative strength of the debt-like or equity-like terms and features given the facts and circumstances, when considering how to weight those terms and features. ASU 2014-16 is effective for public businesses for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. We are currently evaluating the impact of the adoption of this standard on our consolidated financial statements. In April 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-08, Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. ASU 2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance is effective for annual and interim reporting periods beginning after December 15, 2014. Adoption of this amendment will not have a material effect on the Company's financial position or results of operations. In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASU 2014-09”), which establishes a comprehensive new revenue recognition standard designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In doing so, companies may need to use more judgment and make more estimates than under current revenue recognition guidance. ASU 2014-09 allows for the use of either the full or modified retrospective transition method, and the standard will be effective for annual reporting periods beginning after December 15, 2016 including interim periods within that period. Early adoption is not permitted. We are currently evaluating which transition approach to use and the impact of the adoption of this standard on our consolidated financial statements. In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements. There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations or cash flows. |
Organization and Summary of S27
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Capitalized Overhead Expenses | Under the full cost method of accounting, these expenses in the amounts shown in the table below were capitalized in the full cost pool (in thousands). For the Years Ended August 31, 2015 2014 2013 Capitalized overhead $ 2,049 $ 1,230 $ 637 |
Schedule of Customers With Balances Greater Than 10% of Total Receivables | Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table: As of August 31, 2015 2014 2013 Company A 30% 37% 24% Company B * * 23% Company C * * 12% * less than 10% |
Reconciliation of Weighted-average Shares Outstanding Basic and Diluted | The following table sets forth the share calculation of diluted earnings per share: For the Years Ended August 31, 2015 2014 2013 Weighted-average shares outstanding - basic 94,628,665 76,214,737 57,089,362 Potentially dilutive common shares from: Stock options 672,493 479,222 1,881,682 Restricted stock 18,111 — — Warrants — 1,114,095 117,717 Weighted-average shares outstanding - diluted 95,319,269 77,808,054 59,088,761 |
Schedule of Potentially Dilutive Securities | The following potentially dilutive securities outstanding for the fiscal years presented were not included in the respective earnings per share calculation above, as such securities had an anti-dilutive effect on earnings per share: For the Years Ended August 31, 2015 2014 2013 Potentially dilutive common shares from: Stock options 2,785,500 533,000 670,000 Restricted stock 145,000 — — Warrants — — 8,500,000 Total 2,930,500 533,000 9,170,000 |
Property and Equipment (Tables)
Property and Equipment (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Property, Plant and Equipment [Abstract] | |
Schedule of Capitalized Costs | The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands): As of August 31, 2015 2014 Oil and gas properties, full cost method: Unevaluated costs, not subject to amortization: Lease acquisition and other costs $ 58,068 $ 41,531 Wells in progress 19,496 53,747 Subtotal, unevaluated costs 77,564 95,278 Evaluated costs: Producing and non-producing 588,802 329,926 Total capitalized costs 666,366 425,204 Less, accumulated depletion and full cost ceiling impairments (136,409 ) (54,908 ) Oil and gas properties, net 529,957 370,296 Land 4,478 3,898 Other property and equipment 875 5,961 Less, accumulated depreciation (570 ) (755 ) Other property and equipment, net 4,783 9,104 Total property and equipment, net $ 534,740 $ 379,400 |
Schedule of Costs Incurred | Costs incurred in oil and gas property acquisition, exploration and development activities for the fiscal years presented were (in thousands): For the Years Ended August 31, 2015 2014 2013 Acquisition of property: Unproved $ 32,701 $ 15,002 $ 12,295 Proved 51,400 33,795 43,143 Exploration costs 146,892 43,089 — Development costs 4,957 111,238 61,128 Other property and equipment 741 9,315 — Asset retirement obligation 7,051 1,610 1,578 Total costs incurred $ 243,742 $ 214,049 $ 118,144 |
Schedule of Capitalized Costs Excluded from Amortization | The following table summarizes costs related to unevaluated properties that have been excluded from amounts subject to depletion, depreciation, and amortization at August 31, 2015 (in thousands). Period Incurred Total as of 2015 2014 2013 2012 and prior August 31, 2015 Unproved leasehold acquisition costs $ 32,701 $ 8,246 $ 8,007 $ 9,114 $ 58,068 Unevaluated development costs 19,496 — — — 19,496 Total unevaluated costs $ 52,197 $ 8,246 $ 8,007 $ 9,114 $ 77,564 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Bayswater [Member] | |
Business Acquisition [Line Items] | |
Schedule of Fair Value of Acquisition | The following table summarizes the final purchase price and final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price December 15, 2014 Consideration given: Cash $ 74,221 Synergy Resources Corp. Common Stock (1) 48,434 Net liabilities assumed, including asset retirement obligations 3,315 Total consideration given $ 125,970 Allocation of Purchase Price Proved oil and gas properties (2) $ 51,400 Unproved oil and gas properties 6,500 Other assets, including accounts receivable 3,392 Deferred tax asset 23,967 Total fair value of assets acquired $ 85,259 Goodwill $ 40,711 (1) The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of December 15, 2014 ( 4,648,136 shares at $10.42 per share). (2) Proved oil and gas properties were measured primarily using an income approach. The fair value measurements of the oil and gas assets were based, in part, on significant inputs not observable in the market and thus represent a Level 3 measurement. The significant inputs included assumed future production profiles, commodity prices (mainly based on observable market inputs), a discount rate of 10% , and assumptions on the timing and amount of future development and operating costs. |
Schedule of Pro Forma Results | Year Ended August 31, (in thousands) 2015 2014 Oil and gas revenues $ 131,716 $ 108,740 Net income $ 19,822 $ 27,720 Earnings per common share Basic $ 0.21 $ 0.34 Diluted $ 0.21 $ 0.34 |
Trilogy Resources and Apollo Operating [Member] | |
Business Acquisition [Line Items] | |
Schedule of Pro Forma Results | The unaudited pro forma results are not necessarily indicative of what actually would have occurred if the acquisition had been completed as of the beginning of the period, nor are they necessarily indicative of future results. Year Ended August 31, (in thousands) 2014 2013 Oil and gas revenues $ 106,584 $ 55,633 Net income $ 29,681 $ 13,191 Earnings per common share Basic $ 0.39 $ 0.23 Diluted $ 0.38 $ 0.22 |
Trilogy Resources [Member] | |
Business Acquisition [Line Items] | |
Schedule of Fair Value of Acquisition | The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price November 12, 2013 Consideration given: Cash $ 15,902 Synergy Resources Corp. Common Stock * 2,896 Net liabilities assumed, including asset retirement obligations 977 Total consideration given $ 19,775 Allocation of Purchase Price Proved oil and gas properties $ 11,514 Unproved oil and gas properties 7,725 Other assets, including accounts receivable 536 Total fair value of assets acquired $ 19,775 * The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of November 12, 2013 ( 301,339 shares at $9.61 per share). |
Apollo Operating [Member] | |
Business Acquisition [Line Items] | |
Schedule of Fair Value of Acquisition | The following table summarizes the final purchase price and the final fair values of assets acquired and liabilities assumed (in thousands): Purchase Price November 13, 2013 Consideration given: Cash $ 14,688 Synergy Resources Corp. Common Stock * 5,432 Net liabilities assumed, including asset retirement obligation 1,403 Total consideration given $ 21,523 Allocation of Purchase Price Proved oil and gas properties $ 13,284 Unproved oil and gas properties 7,577 Other assets, including accounts receivable 662 Total fair value of assets acquired $ 21,523 * The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock prices on the measurement dates (including 550,518 shares at $9.49 per share on November 13, 2013 plus 20,626 shares at various measurement dates at an average per share price of $10.08 ). |
Depletion, depreciation and a30
Depletion, depreciation and amortization ("DDA") (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Other Costs and Disclosures [Abstract] | |
Schedule of Depletion, Depreciation and Amortization | Depletion, depreciation, accretion, and amortization consisted of the following (in thousands): For the Years Ended August 31, 2015 2014 2013 Depletion of oil and gas properties $ 65,158 $ 32,132 $ 13,046 Depreciation, accretion, and amortization 711 826 290 Total DDA Expense $ 65,869 $ 32,958 $ 13,336 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Fair Value Assumptions | For the purpose of determining the fair value of ARO incurred during the fiscal years presented, the Company used the following assumptions: For the Years Ended August 31, 2015 2014 Inflation rate 3.90% 3.90% Estimated asset life 16.0 - 30.0 years 25.0 - 39.0 years Credit adjusted risk free interest rate 8% 8% |
Schedule of Asset Retirement Obligations | The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands). As of August 31, 2015 2014 Beginning asset retirement obligation $ 4,730 $ 2,777 Liabilities incurred 1,372 1,024 Liabilities assumed 1,913 586 Accretion expense 553 343 Revisions in previous estimates 3,766 — $ 12,334 $ 4,730 |
Commodity Derivative Instrume32
Commodity Derivative Instruments (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Commodity Derivative Contracts | The Company’s commodity derivative contracts as of August 31, 2015 are summarized below: Settlement Period Derivative Instrument Average Volumes (Bbls per month) Average Fixed Price Floor Price Ceiling Price Crude Oil - NYMEX WTI Sep 1, 2015 - Dec 31, 2015 Put 40,000 — $ 50.00 — Sep 1, 2015 - Oct 31, 2015 Put 2,000 — $ 50.00 — Sep 1, 2015 - Dec 31, 2015 Put 10,000 — $ 55.00 — Jan 1, 2016 - Dec 31, 2016 Put 25,000 — $ 50.00 — Jan 1, 2017 - Apr 30, 2017 Put 20,000 — $ 50.00 — May 1, 2017 - Aug 31, 2017 Put 20,000 — $ 55.00 — Settlement Period Derivative Instrument Average Volumes (MMBtu per month) Average Fixed Price Floor Price Ceiling Price Natural Gas - NYMEX Henry Hub Sep 1, 2015 - Dec 31, 2015 Collar 72,000 — $ 4.15 $ 4.49 Jan 1, 2016 - May 31, 2016 Collar 60,000 — $ 4.05 $ 4.54 Jun 1, 2016 - Aug 31, 2016 Collar 60,000 — $ 3.90 $ 4.14 Natural Gas - CIG Rocky Mountain Sep 1, 2015 - Dec 31, 2015 Collar 100,000 — $ 2.20 $ 3.05 Jan 1, 2016 - Dec 31, 2016 Collar 100,000 — $ 2.65 $ 3.10 Jan 1, 2017 - Apr 30, 2017 Collar 100,000 — $ 2.80 $ 3.95 May 1 2017 - Aug 31, 2017 Collar 110,000 — $ 2.50 $ 3.06 Subsequent to August 31, 2015 , the Company added the following position: Settlement Period Derivative Average Volumes Average Floor Price Ceiling Price Crude Oil - NYMEX WTI Jan 1, 2016 - Dec 31, 2016 Put 10,000 — $ 45.00 — |
Schedule of Fair Value of Derivatives | The following table provides a reconciliation between the net assets and liabilities reflected on the accompanying balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contract (in thousands): As of August 31, 2015 Underlying Commodity Balance Sheet Location Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Balance Sheet Net Amounts of Assets and Liabilities Presented in the Balance Sheet Commodity Derivative contracts Current assets $ 3,047 $ (150 ) $ 2,897 Commodity Derivative contracts Noncurrent assets $ 1,774 $ (209 ) $ 1,565 Commodity Derivative contracts Current liabilities $ 150 $ (150 ) $ — Commodity Derivative contracts Noncurrent liabilities $ 209 $ (209 ) $ — As of August 31, 2014 Underlying Commodity Balance Sheet Location Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset in the Balance Sheet Net Amounts of Assets and Liabilities Presented in the Balance Sheet Commodity Derivative contracts Current assets $ 903 $ (538 ) $ 365 Commodity Derivative contracts Noncurrent assets $ 718 $ (664 ) $ 54 Commodity Derivative contracts Current liabilities $ 840 $ (538 ) $ 302 Commodity Derivative contracts Noncurrent liabilities $ 971 $ (664 ) $ 307 |
Schedule of Loss Recognized in Statements of Operations | The amount of gain (loss) recognized in the statements of operations related to derivative financial instruments was as follows (in thousands): For the Years Ended August 31, 2015 2014 2013 Realized gain (loss) on commodity derivatives $ 30,466 $ (2,138 ) $ (395 ) Unrealized gain (loss) on commodity derivatives 1,790 2,459 (2,649 ) Total gain (loss) $ 32,256 $ 321 $ (3,044 ) |
Schedule of Hedge Realized Gains (Losses) | The following table summarizes derivative realized gains and losses during the periods presented (in thousands): Year Ended August 31, 2015 2014 2013 Monthly settlement $ 9,957 $ (2,138 ) $ (395 ) Early liquidation 20,509 — — Total realized gain (loss) $ 30,466 $ (2,138 ) $ (395 ) |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Fair Value Disclosures [Abstract] | |
Schedule of Assets and Liabilities Measured on a Recurring Basis | The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of August 31, 2015 and 2014 by level within the fair value hierarchy (in thousands): Fair Value Measurements at August 31, 2015 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 4,462 $ — $ 4,462 Commodity derivative liability $ — $ — $ — $ — Fair Value Measurements at August 31, 2014 Level 1 Level 2 Level 3 Total Financial assets and liabilities: Commodity derivative asset $ — $ 419 $ — $ 419 Commodity derivative liability $ — $ 609 $ — $ 609 |
Interest Expense (Tables)
Interest Expense (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Interest and Debt Expense [Abstract] | |
Schedule of the Components of Interest Expense | The components of interest expense are (in thousands): For the Years Ended August 31, 2015 2014 2013 Revolving bank credit facility $ 2,776 $ 986 $ 1,067 Amortization of debt issuance costs 853 448 160 Less, interest capitalized (3,384 ) (1,434 ) (1,130 ) Interest expense, net $ 245 $ — $ 97 |
Shareholders' Equity (Tables)
Shareholders' Equity (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Stockholders' Equity Note [Abstract] | |
Schedule of Classes of Stock | The Company's classes of stock are summarized as follows: For the Years Ended August 31, 2015 2014 2013 Preferred stock, shares authorized 10,000,000 10,000,000 10,000,000 Preferred stock, par value $ 0.01 $ 0.01 $ 0.01 Preferred stock, shares issued and outstanding nil nil nil Common stock, shares authorized 200,000,000 200,000,000 100,000,000 Common stock, par value $ 0.001 $ 0.001 $ 0.001 Common stock, shares issued and outstanding 105,099,342 77,999,082 70,587,723 |
Schedule of Common Stock Sold in Public Offering | For the Years Ended August 31, 2015 2014 2013 Number of common shares sold 18,613,952 — 13,225,000 Offering price per common share $ 10.75 $ — $ 6.25 Net proceeds (in thousands) $ 190,845 $ — $ 78,243 |
Schedule of Common Stock Issued For Acquisition of Mineral Interests and Services | For the Years Ended August 31, 2015 2014 2013 Number of common shares issued for mineral property leases 995,672 357,901 687,122 Number of common shares issued for acquisitions 4,648,136 872,483 3,128,422 Total common shares issued 5,643,808 1,230,384 3,815,544 Average price per common share $ 10.67 $ 9.09 $ 4.37 Aggregate value of shares issues (in thousands) $ 60,221 $ 11,184 $ 16,684 |
Schedule of Issued and Outstanding Common Stock Warrants | The following table summarizes activity for common stock warrants for the fiscal years presented: Number of Shares Issuable Upon Warrant Exercise Weighted-Average Exercise Price Per Share Outstanding, August 31, 2012 15,031,067 $ 6.02 Exercised 1,216,265 $ 3.44 Forfeited/Expired 5,148,000 $ 6.74 Outstanding, August 31, 2013 8,666,802 $ 5.92 Exercised 6,104,329 $ 5.88 Forfeited / Expired — $ — Outstanding, August 31, 2014 2,562,473 $ 6.00 Exercised 2,562,473 $ 6.00 Forfeited / Expired — $ — Outstanding, August 31, 2015 — $ — |
Stock-Based Compensation (Table
Stock-Based Compensation (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Stock-based Compensation Expense Recognized | The amount of stock-based compensation expense is as follows (in thousands): For the Years Ended August 31, 2015 2014 2013 Stock options $ 4,741 $ 1,767 $ 1,039 Stock bonus shares 2,950 1,201 277 Investor relations warrants — — 46 $ 7,691 $ 2,968 $ 1,362 |
Schedule of Employee Stock Options Granted During the Period | During the respective fiscal years, the Company granted the following non-qualified stock options: For the Years Ended August 31, 2015 2014 2013 Number of options to purchase common shares 2,377,500 433,000 1,025,000 Weighted-average exercise price $ 11.55 $ 10.37 $ 6.05 Term (in years) 10 years 10 years 10 years Vesting Period (in years) 3-5 years 5 years 3-5 years Fair Value (in thousands) $ 13,266 $ 3,009 $ 4,179 |
Schedule of Assumptions Used In Valuing Stock Options | The assumptions used in valuing stock options granted during each of the fiscal years presented were as follows: For the Years Ended August 31, 2015 2014 2013 Expected term 6.5 years 6.7 years 6.2 years Expected volatility 47 % 73 % 77 % Risk free rate 1.4 - 2.0% 1.8 - 2.3% 0.9 - 2.1% Expected dividend yield 0.0 % 0.0 % 0.0 % Average forfeiture rate 3.5 % 0.0 % 0.0 % |
Summary of Stock Option Activity Under Stock Option | The following table summarizes activity for stock options for the fiscal years presented: Number of Weighted-Average Weighted-Average Aggregate Intrinsic Value Outstanding, August 31, 2012 4,915,000 $ 5.09 2.2 years $ 3,656 Granted 1,025,000 $ 6.05 Exercised (2,120,000 ) $ 1.10 15,690 Forfeited (2,000,000 ) $ 10.00 Outstanding, August 31, 2013 1,820,000 $ 4.88 8.7 years 8,160 Granted 433,000 $ 10.37 Exercised (61,000 ) $ 3.71 481 Expired (25,000 ) $ 10.32 Outstanding, August 31, 2014 2,167,000 $ 5.94 8.0 years 16,287 Granted 2,377,500 $ 11.55 Exercised (258,000 ) $ 3.81 2,103 Forfeited (110,000 ) $ 4.97 Outstanding, August 31, 2015 4,176,500 $ 9.29 8.6 years $ 8,187 Outstanding, Exercisable at August 31, 2015 1,330,600 $ 7.03 7.5 years $ 5,211 Outstanding, Vested and expected to vest at August 31, 2015 4,027,604 $ 9.21 8.6 years $ 8,180 |
Schedule of Issued and Outstanding Stock Options | The following table summarizes information about issued and outstanding stock options as of August 31, 2015 : Outstanding Options Exercisable Options Range of Exercise Prices Options Weighted-Average Remaining Contractual Life Weighted-Average Exercise Price per Share Options Weighted-Average Exercise Price per Share Under $5.00 679,000 6.1 years $ 3.53 463,000 $3.52 $5.00 - $6.99 637,000 7.5 years 6.54 412,000 6.59 $7.00 - $10.99 563,000 8.6 years 9.65 89,600 8.97 $11.00 - $13.46 2,297,500 9.6 years 11.66 366,000 11.50 Total 4,176,500 8.6 years $ 9.29 1,330,600 $7.03 |
Schedule of Unrecognized Compensation Cost | The estimated unrecognized compensation cost from unvested stock options as of August 31, 2015 , which will be recognized ratably over the remaining vesting phase, is as follows: Unvested Options at August 31, 2015 Unrecognized compensation expense (in thousands) $ 12,733 Remaining vesting phase 3.6 years |
Summary of Restricted Stock Awards | The following table summarizes activity for restricted stock awards for the fiscal years presented: Number of Weighted-Average Non-vested, August 31, 2012 13,750 $ 3.06 Granted 109,096 $ 6.41 Vested (76,179 ) $ 5.60 Forfeited — $ — Non-vested, August 31, 2013 46,667 $ 6.75 Granted 343,780 $ 11.34 Vested (97,114 ) $ 11.38 Forfeited — $ — Non-vested, August 31, 2014 293,333 $ 10.60 Granted 547,699 $ 11.17 Vested (208,532 ) $ 11.09 Forfeited — $ — Non-vested, August 31, 2015 632,500 $ 10.93 |
Restricted Stock [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Schedule of Unrecognized Compensation Cost | The estimated unrecognized compensation cost from unvested restricted stock awards as of August 31, 2015 , which will be recognized ratably over the remaining vesting phase, is as follows: Unvested awards as of August 31, 2015 Unrecognized compensation expense (in thousands) $ 6,720 Remaining vesting phase 2.2 years |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Income Tax Disclosure [Abstract] | |
Schedule of Components of Income Taxes | The income tax provision is comprised of the following (in thousands): As of August 31, 2015 2014 2013 Current: Federal $ (4 ) $ 4 $ — State (111 ) 111 — Total current income tax expense (benefit) $ (115 ) $ 115 $ — Deferred: Federal $ 10,820 $ 13,748 $ 6,367 State 972 1,151 503 Total deferred income tax expense $ 11,792 $ 14,899 $ 6,870 Income tax provision $ 11,677 $ 15,014 $ 6,870 |
Schedule of Reconciliation of Income Taxes | A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): As of August 31, 2015 2014 2013 Federal income tax at statutory rate $ 10,105 $ 14,915 $ 5,594 State income taxes, net of federal tax 908 1,341 503 Statutory depletion (451 ) (1,266 ) (929 ) Stock-based compensation 92 — 1,911 Nondeductible compensation 850 125 — Other 173 (101 ) (209 ) Income tax provision $ 11,677 $ 15,014 $ 6,870 Effective rate expressed as a percentage 39 % 34 % 42 % |
Schedule of Deferred Tax Assets and Liabilities | The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the fiscal year ends is presented in the following table (in thousands): As of August 31, 2015 2014 Deferred tax assets: Net operating loss carryforward $ 3,387 $ 8,589 Stock-based compensation 2,788 1,115 Statutory depletion 2,652 2,194 Unrealized loss on commodity derivative — 70 Other 192 4 Gross deferred tax assets $ 9,019 $ 11,972 Deferred tax liabilities: Basis of oil and gas properties 18,433 33,409 Unrealized gain on commodity derivative 593 — Gross deferred tax liabilities 19,026 33,409 Deferred tax liability, net $ 10,007 $ 21,437 |
Related Party Transactions (Tab
Related Party Transactions (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Related Party Transactions [Abstract] | |
Schedule of Rent Expense | Under this agreement, the Company incurred the following expenses to HSLC for the fiscal years presented (in thousands): For the Years Ended August 31, 2015 2014 2013 Rent expense $ 180 $ 180 $ 130 |
Schedule of Share-based Compensation Provided to Related Party | The compensation is paid in the form of restricted shares of the Company’s common stock, as follows: For the Years Ended August 31, 2015 2014 2013 Shares of restricted common stock — 15,883 31,454 Value of common stock (in thousands) $ — $ 106 $ 105 |
Schedule of Mineral Leases Acquired From Related Party | The following table discloses the acquisition of mineral leases from Mr. Seward during each of the fiscal years presented: For the Years Ended August 31, 2015 2014 2013 Mineral acres leased — 4,844 2,263 Shares of restricted common stock — 40,435 22,202 Value of common stock (in thousands) $ — $ 313 $ 91 |
Schedule of Royalty Expense | The following table summarizes the royalty payments made to directors or their affiliates for the fiscal years presented (in thousands): For the Years Ended August 31, 2015 2014 2013 Total royalty payments $ 209 $ 292 $ 304 |
Other Commitments and Conting39
Other Commitments and Contingencies (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Commitments and Contingencies Disclosure [Abstract] | |
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block] | Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next five years, as follows: Year ending August 31, (in MBbls/year) 2016 2,213 2017 4,072 2018 4,072 2019 4,072 2020 4,072 Thereafter 1,860 Total 20,361 |
Supplemental Schedule of Info40
Supplemental Schedule of Information to the Statements of Cash Flows (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of Supplemental Information to the Statements of Cash Flows | The following table supplements the cash flow information presented in the financial statements for the fiscal years presented (in thousands): For the Years Ended August 31, Supplemental cash flow information: 2015 2014 2013 Interest paid $ 2,817 $ 989 $ 995 Income taxes paid 202 — — Non-cash investing and financing activities: Accrued well costs $ 33,071 $ 71,849 $ 25,491 Assets acquired in exchange for common stock 60,221 11,184 16,684 Asset retirement costs and obligations 7,051 1,610 1,578 |
Unaudited Oil and Gas Reserve41
Unaudited Oil and Gas Reserves Information (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | |
Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year | The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and gas reserve quantities and changes therein for each of the fiscal years presented: Oil (MBbl) Gas (MMcf) MBOE Balance, August 31, 2012 5,086 33,446 10,660 Revision of previous estimates (194 ) (2,924 ) (681 ) Purchase of reserves in place 1,000 7,361 2,228 Extensions, discoveries, and other additions 1,576 4,915 2,395 Sale of reserves in place — — — Production (421 ) (2,108 ) (773 ) Balance, August 31, 2013 7,047 40,690 13,829 Revision of previous estimates 83 3,047 591 Purchase of reserves in place 1,028 5,956 2,021 Extensions, discoveries, and other additions 9,142 49,289 17,357 Sale of reserves in place (35 ) (56 ) (44 ) Production (941 ) (3,747 ) (1,566 ) Balance, August 31, 2014 16,324 95,179 32,188 Revision of previous estimates (1,699 ) (4,889 ) (2,513 ) Purchase of reserves in place 4,201 21,957 7,860 Extensions, discoveries, and other additions 11,465 73,392 23,696 Sale of reserves in place (629 ) (4,337 ) (1,352 ) Production (1,970 ) (7,344 ) (3,194 ) Balance, August 31, 2015 27,692 173,958 56,685 Proved developed and undeveloped reserves: Developed at August 31, 2013 4,659 25,866 8,970 Undeveloped at August 31, 2013 2,388 14,824 4,859 Balance, August 31, 2013 7,047 40,690 13,829 Developed at August 31, 2014 6,616 38,162 12,977 Undeveloped at August 31, 2014 9,708 57,017 19,211 Balance, August 31, 2014 16,324 95,179 32,188 Developed at August 31, 2015 7,393 46,026 15,064 Undeveloped at August 31, 2015 20,299 127,932 41,621 Balance, August 31, 2015 27,692 173,958 56,685 |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | For the Years Ended August 31, 2015 2014 2013 Future cash inflow $ 2,046,615 $ 1,839,987 $ 749,030 Future production costs (653,009 ) (395,019 ) (146,352 ) Future development costs (510,720 ) (412,517 ) (108,290 ) Future income tax expense (144,399 ) (252,925 ) (113,545 ) Future net cash flows 738,487 779,526 380,843 10% annual discount for estimated timing of cash flows (372,658 ) (376,827 ) (199,111 ) Standardized measure of discounted future net cash flows $ 365,829 $ 402,699 $ 181,732 |
Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves | Oil (Bbl) Gas (Mcf) August 31, 2013 (Average) $ 86.40 $ 4.40 August 31, 2014 (Average) $ 89.48 $ 5.03 August 31, 2015 (Average) $ 53.27 $ 3.28 |
Schedule of Changes in the Standardized Measure for Discounted Cash Flows | For the Years Ended August 31, 2015 2014 2013 Standardized measure, beginning of year $ 402,699 $ 181,732 $ 102,505 Sale and transfers, net of production costs (98,486 ) (86,808 ) (38,569 ) Net changes in prices and production costs (233,051 ) 15,828 (4,550 ) Extensions, discoveries, and improved recovery 173,918 300,087 70,191 Changes in estimated future development costs 10,002 (20,817 ) (6,006 ) Development costs incurred during the period 4,957 15,000 5,106 Revision of quantity estimates (38,340 ) 4,589 (14,214 ) Accretion of discount 57,629 23,612 35,103 Net change in income taxes 58,547 (76,616 ) (7,850 ) Divestitures of reserves (19,234 ) (925 ) — Purchase of reserves in place 56,795 47,017 40,016 Changes in timing and other (9,607 ) — — Standardized measure, end of year $ 365,829 $ 402,699 $ 181,732 |
Unaudited Quarterly Financial42
Unaudited Quarterly Financial Data (Tables) | 12 Months Ended |
Aug. 31, 2015 | |
Quarterly Financial Information Disclosure [Abstract] | |
Schedule of Unaudited Quarterly Financial Data | The Company’s unaudited quarterly financial information for the years ended August 31, 2015 and 2014 is as follows (in thousands, except share data): For the Year Ended August 31, 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 42,538 $ 23,713 $ 26,033 $ 32,559 Expenses 27,783 25,417 29,102 44,919 Operating income (loss) 14,755 (1,704 ) (3,069 ) (12,360 ) Other income (expense) 18,140 9,563 (1,245 ) 5,639 Income (loss) before income taxes 32,895 7,859 (4,314 ) (6,721 ) Income tax provision (benefit) 11,744 3,207 (1,833 ) (1,441 ) Net income (loss) $ 21,151 $ 4,652 $ (2,481 ) $ (5,280 ) Net income (loss) per common share: (1) Basic $ 0.27 $ 0.05 $ (0.02 ) $ (0.05 ) Diluted $ 0.26 $ 0.05 $ (0.02 ) $ (0.05 ) Weighted-average shares outstanding: Basic 79,008,719 89,903,288 104,234,519 105,084,651 Diluted 80,141,152 90,636,107 (2) (2) For the Year Ended August 31, 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Revenues $ 19,266 $ 23,028 $ 25,672 $ 36,253 Expenses 12,048 13,550 14,413 20,744 Operating income 7,218 9,478 11,259 15,509 Other income (expense) 2,269 (1,979 ) (983 ) 1,096 Income before income taxes 9,487 7,499 10,276 16,605 Income tax provision 3,387 2,338 3,116 6,173 Net income $ 6,100 $ 5,161 $ 7,160 $ 10,432 Net income per common share: (1) Basic $ 0.08 $ 0.07 $ 0.09 $ 0.13 Diluted $ 0.08 $ 0.07 $ 0.09 $ 0.13 Weighted-average shares outstanding: Basic 73,674,865 76,203,938 77,176,420 77,771,916 Diluted 76,044,605 77,990,416 79,008,619 79,698,720 1 The sum of net income (loss) per common share for the four quarters may not agree with the annual amount reported because the number used as the denominator for each quarterly computation is based on the weighted-average number of shares outstanding during that quarter whereas the annual computation is based upon an average for the entire year. 2 Common share equivalents were excluded from the calculation of net income (loss) per share as the inclusion of the common share equivalents was anti-dilutive. |
Organization and Summary of S43
Organization and Summary of Significant Accounting Policies (Details) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015USD ($)customer | Aug. 31, 2014USD ($)customer | Aug. 31, 2013USD ($)customer | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Net cash flows, discount rate (percent) | 10.00% | ||
Capitalized overhead | $ 2,049 | $ 1,230 | $ 637 |
Concentration Risk [Line Items] | |||
Number of major customers | customer | 2 | 2 | 2 |
Minimum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Other property and equipment, useful life | 5 years | ||
Maximum [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Other property and equipment, useful life | 7 years | ||
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company A [Member] | |||
Concentration Risk [Line Items] | |||
Risk percentage | 65.00% | 54.00% | 50.00% |
Customer Concentration Risk [Member] | Oil and Gas Revenues [Member] | Company B [Member] | |||
Concentration Risk [Line Items] | |||
Risk percentage | 11.00% | 13.00% | 15.00% |
Customer Concentration Risk [Member] | Accounts receivable [Member] | Company A [Member] | |||
Concentration Risk [Line Items] | |||
Risk percentage | 30.00% | 37.00% | 24.00% |
Customer Concentration Risk [Member] | Accounts receivable [Member] | Company B [Member] | |||
Concentration Risk [Line Items] | |||
Risk percentage | 23.00% | ||
Customer Concentration Risk [Member] | Accounts receivable [Member] | Company C [Member] | |||
Concentration Risk [Line Items] | |||
Risk percentage | 12.00% |
Organization and Summary of S44
Organization and Summary of Significant Accounting Policies (Earnings Per Share) (Details) - shares | 3 Months Ended | 12 Months Ended | |||||||||
Aug. 31, 2015 | May. 31, 2015 | Feb. 28, 2015 | Nov. 30, 2014 | Aug. 31, 2014 | May. 31, 2014 | Feb. 28, 2014 | Nov. 30, 2013 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||||||||||
Weighted-average shares outstanding - basic | 105,084,651 | 104,234,519 | 89,903,288 | 79,008,719 | 77,771,916 | 77,176,420 | 76,203,938 | 73,674,865 | 94,628,665 | 76,214,737 | 57,089,362 |
Potentially dilutive common shares from: | |||||||||||
Stock options | 672,493 | 479,222 | 1,881,682 | ||||||||
Restricted stock | 18,111 | 0 | 0 | ||||||||
Warrants | 0 | 1,114,095 | 117,717 | ||||||||
Weighted-average shares outstanding - diluted | 90,636,107 | 80,141,152 | 79,698,720 | 79,008,619 | 77,990,416 | 76,044,605 | 95,319,269 | 77,808,054 | 59,088,761 | ||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 2,930,500 | 533,000 | 9,170,000 | ||||||||
Warrants [Member] | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 0 | 0 | 8,500,000 | ||||||||
Restricted Stock [Member] | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 145,000 | 0 | 0 | ||||||||
Stock Options [Member] | |||||||||||
Potentially dilutive common shares from: | |||||||||||
Potentially dilutive common shares having anti-dilutive effect on earnings per share | 2,785,500 | 533,000 | 670,000 |
Property and Equipment (Narrati
Property and Equipment (Narrative) (Details) $ in Thousands | 12 Months Ended | ||||
Aug. 31, 2015USD ($)$ / bbl | Aug. 31, 2014USD ($)$ / bbl$ / Mcf | Aug. 31, 2013USD ($)$ / bbl$ / Mcf | Aug. 31, 2015$ / MMBTU | Aug. 31, 2015$ / Mcf | |
Reserve Quantities [Line Items] | |||||
Prices per unit, percentage change | 40.00% | ||||
Full cost ceiling impairment | $ 16,000 | $ 0 | $ 0 | ||
Unproved properties impairment | 16,000 | $ 0 | $ 0 | ||
Unproved Properties [Member] | |||||
Reserve Quantities [Line Items] | |||||
Unproved properties impairment | $ 15,400 | ||||
Oil (Bbl) [Member] | |||||
Reserve Quantities [Line Items] | |||||
Prices per unit | $ / bbl | 53.27 | 89.48 | 86.40 | ||
Natural Gas [Member] | |||||
Reserve Quantities [Line Items] | |||||
Prices per unit | 5.03 | 4.40 | 3.28 | 3.28 |
Property and Equipment (Schedul
Property and Equipment (Schedule of Capitalized Costs) (Details) - USD ($) $ in Thousands | Aug. 31, 2015 | Aug. 31, 2014 |
Unevaluated costs, not subject to amortization: | ||
Unevaluated costs, not subject to amortization | $ 77,564 | |
Unevaluated oil and gas properties | 77,564 | $ 95,278 |
Evaluated costs: | ||
Producing and non-producing | 588,802 | 329,926 |
Total capitalized costs | 666,366 | 425,204 |
Less, accumulated depletion and full cost ceiling impairments | (136,409) | (54,908) |
Oil and gas properties, net | 529,957 | 370,296 |
Other property and equipment: | ||
Other property and equipment, gross | 875 | 5,961 |
Less, accumulated depreciation | (570) | (755) |
Other property and equipment, net | 4,783 | 9,104 |
Total property and equipment, net | 534,740 | 379,400 |
Land [Member] | ||
Other property and equipment: | ||
Other property and equipment, gross | 4,478 | 3,898 |
Lease acquisition and other costs [Member] | ||
Unevaluated costs, not subject to amortization: | ||
Unevaluated costs, not subject to amortization | 58,068 | 41,531 |
Wells in progress [Member] | ||
Unevaluated costs, not subject to amortization: | ||
Unevaluated costs, not subject to amortization | $ 19,496 | $ 53,747 |
Property and Equipment (Sched47
Property and Equipment (Schedule of Costs Incurred) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Acquisition of property: | |||
Unproved | $ 32,701 | $ 15,002 | $ 12,295 |
Proved | 51,400 | 33,795 | 43,143 |
Exploration costs | 146,892 | 43,089 | 0 |
Development costs | 4,957 | 111,238 | 61,128 |
Other property and equipment | 741 | 9,315 | 0 |
Asset retirement obligation | 7,051 | 1,610 | 1,578 |
Total costs Incurred | $ 243,742 | $ 214,049 | $ 118,144 |
Property and Equipment (Sched48
Property and Equipment (Schedule of Capitalized Costs Excluded from Amortization) (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | Aug. 31, 2012 | |
Property, Plant and Equipment [Line Items] | ||||
Total unevaluated costs | $ 52,197 | $ 8,246 | $ 8,007 | $ 9,114 |
Unevaluated costs, not subject to amortization | 77,564 | |||
Unproved leasehold acquisition costs [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total unevaluated costs | 32,701 | 8,246 | 8,007 | 9,114 |
Unevaluated costs, not subject to amortization | 58,068 | 41,531 | ||
Unevaluated development costs [Member] | ||||
Property, Plant and Equipment [Line Items] | ||||
Total unevaluated costs | 19,496 | 0 | $ 0 | $ 0 |
Unevaluated costs, not subject to amortization | $ 19,496 | $ 53,747 |
Acquisitions (Narrative) (Detai
Acquisitions (Narrative) (Details) $ in Thousands | Dec. 15, 2014USD ($)awellcompanyshares | Nov. 13, 2013USD ($)awelldisposal_wellshares | Nov. 12, 2013USD ($)shares | Aug. 31, 2015USD ($) | Aug. 31, 2015USD ($)shares | Aug. 31, 2014USD ($)transactionshares | Aug. 31, 2013USD ($)shares | Sep. 16, 2013awell |
Business Acquisition [Line Items] | ||||||||
Total purchase price | $ 19,775 | |||||||
Goodwill | $ 40,711 | $ 40,711 | $ 0 | |||||
Number of transactions completed | transaction | 2 | |||||||
Business acquisition, shares issued | shares | 4,648,136 | 872,483 | 3,128,422 | |||||
Business acquisition, shares issued, value | $ 48,434 | $ 8,328 | $ 13,518 | |||||
Unevaluated oil and gas properties | 77,564 | 77,564 | 95,278 | |||||
Producing and non-producing | 588,802 | $ 588,802 | $ 329,926 | |||||
Bayswater [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Number of independent out and gas companies | company | 3 | |||||||
Total purchase price | $ 125,970 | |||||||
Cash | 74,221 | |||||||
Synergy Resources Corp. Common Stock | 48,434 | |||||||
Deferred tax asset | 23,967 | |||||||
Goodwill | 40,711 | |||||||
Unproved oil and gas properties | $ 6,500 | |||||||
Amount reclassified to goodwill and deferred tax asset | 64,700 | |||||||
Pro forma revenue since acquisition date | 7,700 | |||||||
Pro forma net income since acquisition date | 4,800 | |||||||
Business acquisition, shares issued | shares | 4,648,136 | |||||||
Bayswater [Member] | Codell And Niobrara [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Mineral acres, net | a | 4,227 | |||||||
Bayswater [Member] | Sussex Shannon And JSands [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Mineral acres, net | a | 1,480 | |||||||
Bayswater [Member] | Horizontal Wells [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Number of wells | well | 17 | |||||||
Bayswater [Member] | Horizontal Wells [Member] | Minimum [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percent of entity acquired | 6.00% | |||||||
Bayswater [Member] | Horizontal Wells [Member] | Maximum [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percent of entity acquired | 40.00% | |||||||
Bayswater [Member] | Vertical Wells [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Number of wells | well | 73 | |||||||
Bayswater [Member] | Vertical Wells [Member] | Minimum [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percent of entity acquired | 5.00% | |||||||
Bayswater [Member] | Vertical Wells [Member] | Maximum [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percent of entity acquired | 100.00% | |||||||
Bayswater [Member] | Non Operated Vertical Wells [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Number of wells | well | 11 | |||||||
Trilogy Resources [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Cash | 15,902 | $ 15,900 | ||||||
Synergy Resources Corp. Common Stock | 2,896 | |||||||
Mineral acres, net | a | 800 | |||||||
Number of wells | well | 21 | |||||||
Unproved oil and gas properties | $ 7,725 | |||||||
Business acquisition, shares issued | shares | 301,339 | 301,339 | ||||||
Business acquisition, shares issued, value | $ 2,900 | |||||||
Apollo Operating [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Total purchase price | 21,523 | |||||||
Cash | 14,688 | |||||||
Synergy Resources Corp. Common Stock | $ 5,432 | |||||||
Number of wells | well | 38 | |||||||
Percent of entity acquired | 25.00% | |||||||
Unproved oil and gas properties | $ 7,577 | |||||||
Business acquisition, shares issued | shares | 550,518 | 20,626 | ||||||
Number of water disposal wells | disposal_well | 1 | |||||||
Apollo Operating Assets [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Cash | $ 11,000 | |||||||
Mineral acres, net | a | 1,000 | |||||||
Business acquisition, shares issued | shares | 550,518 | |||||||
Business acquisition, shares issued, value | $ 5,200 | |||||||
Mineral acres, gross | a | 3,639 | |||||||
Related Interests [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Cash | $ 3,700 | |||||||
Business acquisition, shares issued | shares | 20,626 | |||||||
Business acquisition, shares issued, value | $ 200 | |||||||
Trilogy Resources and Apollo Operating [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Unevaluated oil and gas properties | $ 15,300 | $ 15,300 | ||||||
Unproved properties not subject to amortization (percent) | 2.00% | 2.00% | ||||||
Trilogy Resources and Apollo Operating [Member] | Horizontal Wells [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Producing and non-producing | $ 24,800 | $ 24,800 | ||||||
Trilogy Resources and Apollo Operating [Member] | Vertical Wells [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Percent of entity acquired | 100.00% | 100.00% |
Acquisitions (Schedule of Fair
Acquisitions (Schedule of Fair Value of Acquisition) (Details) - USD ($) $ / shares in Units, $ in Thousands | Dec. 15, 2014 | Nov. 13, 2013 | Nov. 12, 2013 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 |
Preliminary Purchase Price | ||||||
Total consideration given | $ 19,775 | |||||
Preliminary Allocation of Purchase Price | ||||||
Goodwill | $ 40,711 | $ 0 | ||||
Business acquisition, shares issued | 4,648,136 | 872,483 | 3,128,422 | |||
Net cash flows, discount rate (percent) | 10.00% | |||||
Bayswater [Member] | ||||||
Preliminary Purchase Price | ||||||
Cash | $ 74,221 | |||||
Synergy Resources Corp. Common Stock | 48,434 | |||||
Net liabilities assumed, including asset retirement obligations | 3,315 | |||||
Total consideration given | 125,970 | |||||
Preliminary Allocation of Purchase Price | ||||||
Proved oil and gas properties | 51,400 | |||||
Unproved oil and gas properties | 6,500 | |||||
Other assets, including accounts receivable | 3,392 | |||||
Deferred tax asset | 23,967 | |||||
Total fair value of oil and gas properties acquired | 85,259 | |||||
Goodwill | $ 40,711 | |||||
Business acquisition, shares issued | 4,648,136 | |||||
Closing stock price (in dollars per share) | $ 10.42 | |||||
Net cash flows, discount rate (percent) | 10.00% | |||||
Trilogy Resources [Member] | ||||||
Preliminary Purchase Price | ||||||
Cash | 15,902 | $ 15,900 | ||||
Synergy Resources Corp. Common Stock | 2,896 | |||||
Net liabilities assumed, including asset retirement obligations | 977 | |||||
Preliminary Allocation of Purchase Price | ||||||
Proved oil and gas properties | 11,514 | |||||
Unproved oil and gas properties | 7,725 | |||||
Other assets, including accounts receivable | 536 | |||||
Total fair value of oil and gas properties acquired | $ 19,775 | |||||
Business acquisition, shares issued | 301,339 | 301,339 | ||||
Closing stock price (in dollars per share) | $ 9.61 | |||||
Apollo Operating [Member] | ||||||
Preliminary Purchase Price | ||||||
Cash | $ 14,688 | |||||
Synergy Resources Corp. Common Stock | 5,432 | |||||
Net liabilities assumed, including asset retirement obligations | 1,403 | |||||
Total consideration given | 21,523 | |||||
Preliminary Allocation of Purchase Price | ||||||
Proved oil and gas properties | 13,284 | |||||
Unproved oil and gas properties | 7,577 | |||||
Other assets, including accounts receivable | 662 | |||||
Total fair value of oil and gas properties acquired | $ 21,523 | |||||
Business acquisition, shares issued | 550,518 | 20,626 | ||||
Closing stock price (in dollars per share) | $ 9.49 | $ 10.08 |
Acquisitions (Schedule of Pro F
Acquisitions (Schedule of Pro Forma Results) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Trilogy Resources and Apollo Operating [Member] | |||
Business Acquisition [Line Items] | |||
Oil and Gas Revenues | $ 106,584 | $ 55,633 | |
Net income | $ 29,681 | $ 13,191 | |
Earnings per common share | |||
Basic (in dollars per share) | $ 0.39 | $ 0.23 | |
Diluted (in dollars per share) | $ 0.38 | $ 0.22 | |
Bayswater [Member] | |||
Business Acquisition [Line Items] | |||
Oil and Gas Revenues | $ 131,716 | $ 108,740 | |
Net income | $ 19,822 | $ 27,720 | |
Earnings per common share | |||
Basic (in dollars per share) | $ 0.21 | $ 0.34 | |
Diluted (in dollars per share) | $ 0.21 | $ 0.34 |
Depletion, depreciation and a52
Depletion, depreciation and amortization ("DDA") (Details) Boe in Thousands, $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015USD ($)Boe$ / Boe | Aug. 31, 2014USD ($)Boe$ / Boe | Aug. 31, 2013USD ($)$ / Boe | |
Other Costs and Disclosures [Abstract] | |||
Depletion of oil and gas properties | $ 65,158 | $ 32,132 | $ 13,046 |
Depreciation, accretion, and amortization | 711 | 826 | 290 |
Total DDA Expense | $ 65,869 | $ 32,958 | $ 13,336 |
Production of BOE (in Boe's) | Boe | 3,194 | 1,566 | |
Percentage of total reserves | 5.30% | 4.60% | |
DDA expense per BOE (in dollars per BOE) | $ / Boe | 20.62 | 21.05 | 17.26 |
Asset Retirement Obligations (S
Asset Retirement Obligations (Schedule of Fair Value Assumptions) (Details) | 12 Months Ended | |
Aug. 31, 2015 | Aug. 31, 2014 | |
Inflation rate | 3.90% | 3.90% |
Credit adjusted risk free interest rate | 8.00% | 8.00% |
Minimum [Member] | ||
Estimated asset life | 16 years | 25 years |
Maximum [Member] | ||
Estimated asset life | 30 years | 39 years |
Asset Retirement Obligations 54
Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Aug. 31, 2015 | Aug. 31, 2014 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning asset retirement obligation | $ 4,730 | $ 2,777 |
Liabilities incurred | 1,372 | 1,024 |
Liabilities assumed | 1,913 | 586 |
Accretion expense | 553 | 343 |
Revisions in previous estimates | 3,766 | 0 |
Ending asset retirement obligation | $ 12,334 | $ 4,730 |
Revolving Credit Facility (Deta
Revolving Credit Facility (Details) | Jun. 02, 2015USD ($) | Aug. 31, 2015USD ($) | Aug. 31, 2014USD ($) | Jun. 04, 2014 |
Line of Credit Facility [Line Items] | ||||
Total borrowing commitment | $ 500,000,000 | |||
Borrowing base | $ 163,000,000 | |||
Amount outstanding | 78,000,000 | $ 37,000,000 | ||
Remaining borrowing capacity | $ 85,000,000 | |||
Average interest rate | 2.50% | |||
Rolling period of hedge position | 24 months | |||
Minimum hedge percentage of scheduled production for a rolling 24 months, as required by revolving credit facility covenants | 45.00% | |||
Maximum hedge percentage of scheduled production for a rolling 24 months, as required by revolving credit facility covenants | 85.00% | |||
Maximum funded debt to EBITDAX | 4 | |||
Debt Covenant Minimum Liquidity Amount | $ 25,000,000 | |||
Minimum [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Revolving credit facility, additional rate over variable | 2.50% |
Commodity Derivative Instrume56
Commodity Derivative Instruments (Schedule of Commodity Derivative Contracts) (Details) MMBTU / mo in Thousands | 1 Months Ended | 12 Months Ended |
Oct. 15, 2015bbl / mo$ / bbl | Aug. 31, 2015MMBTU / mobbl / mo$ / bbl$ / MMBTU | |
Contract One [Member] | Put [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 40,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 50 | |
Ceiling Price | $ / bbl | 0 | |
Contract One [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 72 | |
Average Fixed Price | 0 | |
Floor Price | 4.15 | |
Ceiling Price | 4.49 | |
Contract Two [Member] | Put [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 2,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 50 | |
Ceiling Price | $ / bbl | 0 | |
Contract Two [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 60 | |
Average Fixed Price | 0 | |
Floor Price | 4.05 | |
Ceiling Price | 4.54 | |
Contract Three [Member] | Put [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 10,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 55 | |
Ceiling Price | $ / bbl | 0 | |
Contract Three [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 60 | |
Average Fixed Price | 0 | |
Floor Price | 3.90 | |
Ceiling Price | 4.14 | |
Contract Four [Member] | Put [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 25,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 50 | |
Ceiling Price | $ / bbl | 0 | |
Contract Five [Member] | Put [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 20,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 50 | |
Ceiling Price | $ / bbl | 0 | |
Contract Five [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 100 | |
Average Fixed Price | 0 | |
Floor Price | 2.20 | |
Ceiling Price | 3.05 | |
Contract Six [Member] | Put [Member] | Crude Oil [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 20,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 55 | |
Ceiling Price | $ / bbl | 0 | |
Contract Six [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 100 | |
Average Fixed Price | 0 | |
Floor Price | 2.65 | |
Ceiling Price | 3.10 | |
Contract Seven [Member] | Put [Member] | Crude Oil [Member] | Subsequent Event [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volume (BBl's per month) | bbl / mo | 10,000 | |
Average Fixed Price | $ / bbl | 0 | |
Floor Price | $ / bbl | 45 | |
Ceiling Price | $ / bbl | 0 | |
Contract Seven [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 100 | |
Average Fixed Price | 0 | |
Floor Price | 2.80 | |
Ceiling Price | 3.95 | |
Contract Eight [Member] | Collar [Member] | Natural Gas [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Average Volumes (MMBtu per month) | MMBTU / mo | 110 | |
Average Fixed Price | 0 | |
Floor Price | 2.50 | |
Ceiling Price | 3.06 |
Commodity Derivative Instrume57
Commodity Derivative Instruments (Schedule of Fair Value of Derivatives) (Details) - Commodity Derivative Contracts [Member] - USD ($) $ in Thousands | Aug. 31, 2015 | Aug. 31, 2014 |
Current Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | $ 3,047 | $ 903 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | (150) | (538) |
Derivative asset, Net | 2,897 | 365 |
Noncurrent Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative asset, Gross Amount Recognized | 1,774 | 718 |
Derivative asset, Gross Amounts Offset in the Balance Sheet | (209) | (664) |
Derivative asset, Net | 1,565 | 54 |
Current Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liability, Gross Amount Recognized | 150 | 840 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | (150) | (538) |
Derivative liability, Net | 0 | 302 |
Noncurrent Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Derivative liability, Gross Amount Recognized | 209 | 971 |
Derivative liability, Gross Amounts Offset in the Balance Sheet | (209) | (664) |
Derivative liability, Net | $ 0 | $ 307 |
Commodity Derivative Instrume58
Commodity Derivative Instruments (Schedule of Gain (Loss) Recognized in Statements of Operations) (Details) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015USD ($)$ / bblbbl | Aug. 31, 2014USD ($) | Aug. 31, 2013USD ($) | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Early liquidation | $ 20,509 | $ 0 | $ 0 |
Average price of liquidated swaps (in dollars per share) | $ / bbl | 82.79 | ||
Realized gain (loss) on commodity derivatives | $ 30,466 | (2,138) | (395) |
Unrealized gain (loss) on commodity derivatives | 1,790 | 2,459 | (2,649) |
Total gain (loss) | $ 32,256 | $ 321 | $ (3,044) |
Number of barrels liquidated (in bbl) | bbl | 372,500 |
Commodity Derivative Instrume59
Commodity Derivative Instruments (Schedule of Hedge Realized Gains (Losses)) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Monthly settlement | $ 9,957 | $ (2,138) | $ (395) |
Early liquidation | 20,509 | 0 | 0 |
Total realized gain (loss) | $ 30,466 | $ (2,138) | $ (395) |
Commodity Derivative Instrume60
Commodity Derivative Instruments (Narrative) (Details) | Aug. 31, 2015counterparty |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 4 |
Credit Facility Syndicate [Member] | |
Accounts, Notes, Loans and Financing Receivable [Line Items] | |
Number of counterparties | 2 |
Fair Value Measurements (Detail
Fair Value Measurements (Details) - Recurring [Member] - USD ($) $ in Thousands | Aug. 31, 2015 | Aug. 31, 2014 |
Financial Assets: | ||
Commodity derivative asset | $ 4,462 | $ 419 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 609 |
Level 1 [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 0 |
Level 2 [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 4,462 | 419 |
Financial Liabilities: | ||
Commodity derivative liability | 0 | 609 |
Level 3 [Member] | ||
Financial Assets: | ||
Commodity derivative asset | 0 | 0 |
Financial Liabilities: | ||
Commodity derivative liability | $ 0 | $ 0 |
Interest Expense (Details)
Interest Expense (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Interest and Debt Expense [Abstract] | |||
Revolving bank credit facility | $ 2,776 | $ 986 | $ 1,067 |
Amortization of debt issuance costs | 853 | 448 | 160 |
Less, interest capitalized | (3,384) | (1,434) | (1,130) |
Interest expense, net | $ 245 | $ 0 | $ 97 |
Shareholders' Equity (Common St
Shareholders' Equity (Common Stock Transactions) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Classes of stock | |||
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 |
Preferred stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Preferred stock, shares issued | 0 | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 | 0 |
Common stock, shares authorized | 200,000,000 | 200,000,000 | 100,000,000 |
Common stock, par value | $ 0.001 | $ 0.001 | $ 0.001 |
Common stock, shares issued | 105,099,342 | 77,999,082 | 70,587,723 |
Common stock, shares outstanding | 105,099,342 | 77,999,082 | 70,587,723 |
Sale of common stock | |||
Number of common shares sold | 18,613,952 | 0 | 13,225,000 |
Offering price per common share (in dollars per share) | $ 10.75 | $ 0 | $ 6.25 |
Net proceeds | $ 190,845 | $ 0 | $ 78,243 |
Common stock issued for acquisition of mineral interests | |||
Number of common shares issued for mineral property leases | 995,672 | 357,901 | 687,122 |
Number of common shares issued for acquisitions | 4,648,136 | 872,483 | 3,128,422 |
Number of common shares sold | 5,643,808 | 1,230,384 | 3,815,544 |
Average price per common share (in dollars per share) | $ 10.67 | $ 9.09 | $ 4.37 |
Aggregate value of shares issued | $ 60,221 | $ 11,184 | $ 16,684 |
Shareholders' Equity (Common 64
Shareholders' Equity (Common Stock Warrants) (Details) | 12 Months Ended | |||||
Aug. 31, 2015$ / sharesshares | Aug. 31, 2014$ / sharesshares | Aug. 31, 2013$ / sharesshares | Aug. 31, 2010USD ($)noteshares | Aug. 31, 2009$ / sharesshares | Aug. 31, 2011$ / sharesshares | |
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||
Outstanding, Beginning balance (shares) | 2,562,473 | 8,666,802 | 15,031,067 | |||
Exercised (shares) | 2,562,473 | 6,104,329 | 1,216,265 | |||
Forfeited / Expired (shares) | 0 | 0 | 5,148,000 | |||
Outstanding, Ending balance (shares) | 0 | 2,562,473 | 8,666,802 | |||
Weighted average exercise price, Beginning balance (in dollars per share) | $ / shares | $ 6 | $ 5.92 | $ 6.02 | |||
Weighted average exercise price, exercised (in dollars per share) | $ / shares | 6 | 5.88 | 3.44 | |||
Weighted average exercise price, forfeited/expired (in dollars per share) | $ / shares | 0 | 0 | 6.74 | |||
Weighted average exercise price, Ending balance (in dollars per share) | $ / shares | $ 0 | $ 6 | $ 5.92 | |||
Series A [Member] | ||||||
Class of Warrant or Right [Line Items] | ||||||
Number of warrants issued (shares) | 4,098,000 | |||||
Number of shares of common stock per warrant | 1 | |||||
Exercise Price (in dollars per share) | $ / shares | $ 6 | |||||
Series B [Member] | ||||||
Class of Warrant or Right [Line Items] | ||||||
Number of warrants issued (shares) | 1,000,000 | |||||
Number of shares of common stock per warrant | 1 | |||||
Exercise Price (in dollars per share) | $ / shares | $ 10 | |||||
Series C [Member] | ||||||
Class of Warrant or Right [Line Items] | ||||||
Number of warrants issued (shares) | 9,000,000 | |||||
Unit Offering, Number of Convertible Promissory Note | note | 1 | |||||
Face value of promissory note | $ | $ 100,000 | |||||
Class of Warrant or Right, Number of Shares Called by Each Unit | 50,000 | |||||
Number of shares of common stock per warrant | 1 | |||||
Exercise Price (in dollars per share) | $ / shares | $ 6 | |||||
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||
Exercised (shares) | 2,561,415 | 5,938,585 | 500,000 | |||
Series D [Member] | ||||||
Class of Warrant or Right [Line Items] | ||||||
Number of warrants issued (shares) | 1,125,000 | |||||
Number of shares of common stock per warrant | 1 | |||||
Exercise Price (in dollars per share) | $ / shares | $ 1.60 | |||||
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||
Exercised (shares) | 1,058 | 140,744 | 627,799 | |||
Sales Agent Warrants [Member] | ||||||
Class of Warrant or Right [Line Items] | ||||||
Number of warrants issued (shares) | 31,733 | |||||
Number of shares of common stock per warrant | 2 | |||||
Exercise Price (in dollars per share) | $ / shares | $ 1.80 | |||||
Investor Relation Warrants [Member] | ||||||
Class of Warrant or Right [Line Items] | ||||||
Number of warrants issued (shares) | 100,000 | |||||
Number of shares of common stock per warrant | 1 | |||||
Exercise Price (in dollars per share) | $ / shares | $ 2.69 | |||||
Schedule of Common Stock Warrant Activity [Roll Forward] | ||||||
Granted (shares) | 50,000 | |||||
Exercised (shares) | 0 | 25,000 | 25,000 | |||
Forfeited / Expired (shares) | 50,000 |
Stock-Based Compensation (Narra
Stock-Based Compensation (Narrative) (Details) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015USD ($)planshares | Aug. 31, 2014 | Aug. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of plans | plan | 3 | ||
Unrecognized compensation expense | $ | $ 12,733 | ||
Remaining vesting phase | 3 years 7 months 6 days | ||
Vesting period | 5 years | ||
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | 3 years | |
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 5 years | 5 years | |
Non-qualified plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares authorized | 5,000,000 | ||
Number of shares available for grant | 384,500 | ||
Incentive stock option plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares authorized | 2,000,000 | ||
Number of shares available for grant | 2,000,000 | ||
Stock bonus plan [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of shares authorized | 2,000,000 | ||
Number of shares available for grant | 723,937 | ||
Restricted Stock [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation expense | $ | $ 6,720 | ||
Remaining vesting phase | 2 years 2 months 12 days | ||
Restricted Stock [Member] | Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 3 years | ||
Restricted Stock [Member] | Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting period | 5 years |
Stock-Based Compensation (Stock
Stock-Based Compensation (Stock Based Compensation Expense) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation expense | $ 7,691 | $ 2,968 | $ 1,362 |
Stock options [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation expense | 4,741 | 1,767 | 1,039 |
Stock bonus shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation expense | 2,950 | 1,201 | 277 |
Investor relations warrants [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost [Line Items] | |||
Stock-based compensation expense | $ 0 | $ 0 | $ 46 |
Stock-Based Compensation (Non-Q
Stock-Based Compensation (Non-Qualified Stock Options Granted) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Number of options to purchase common shares | 2,377,500 | 433,000 | 1,025,000 |
Weighted-average exercise price (in dollars per share) | $ 11.55 | $ 10.37 | $ 6.05 |
Term | 10 years | 10 years | 10 years |
Vesting Period | 5 years | ||
Fair Value | $ 13,266 | $ 3,009 | $ 4,179 |
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting Period | 3 years | 3 years | |
Maximum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Vesting Period | 5 years | 5 years |
Stock-Based Compensation (Sto68
Stock-Based Compensation (Stock Option Assumptions) (Details) | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected term | 6 years 6 months | 6 years 8 months 12 days | 6 years 2 months 12 days |
Expected volatility (percent) | 47.00% | 73.00% | 77.00% |
Risk-free rate, minimum (percent) | 1.40% | 1.80% | 0.90% |
Risk-free rate, maximum (percent) | 2.00% | 2.30% | 2.10% |
Expected dividend yield (percent) | 0.00% | 0.00% | 0.00% |
Average forfeiture rate (percent) | 3.50% | 0.00% | |
Minimum [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Average forfeiture rate (percent) | 0.00% |
Stock-Based Compensation (Sto69
Stock-Based Compensation (Stock Option Activity) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | Aug. 31, 2012 | |
Summary of activity for stock options (in shares): | ||||
Outstanding, Beginning balance (shares) | 2,167,000 | 1,820,000 | 4,915,000 | |
Granted (shares) | 2,377,500 | 433,000 | 1,025,000 | |
Exercised (shares) | (258,000) | (61,000) | (2,120,000) | |
Forfeited (shares) | (110,000) | (2,000,000) | ||
Expired (shares) | (25,000) | |||
Outstanding, Ending balance (shares) | 4,176,500 | 2,167,000 | 1,820,000 | 4,915,000 |
Outstanding, Exercisable at end of period (shares) | 1,330,600 | |||
Outstanding, Vested and expected to vest at end of period (shares) | 4,027,604 | |||
Weighted Average Exercise Price (in dollars per share): | ||||
Beginning balance, Weighted average exercise price (in dollars per share) | $ 5.94 | $ 4.88 | $ 5.09 | |
Granted, weighted average exercise price (in dollars per share) | 11.55 | 10.37 | 6.05 | |
Exercised, weighted average exercise price (in dollars per share) | 3.81 | 3.71 | 1.10 | |
Forfeited, weighted average exercise price (in dollars per share) | 4.97 | 10 | ||
Expired, weighted average exercise price (in dollars per share) | 10.32 | |||
Ending balance, Weighted average exercise price (in dollars per share) | 9.29 | $ 5.94 | $ 4.88 | $ 5.09 |
Outstanding, exercisable, weighted average exercise price (in dollars per share) | 7.03 | |||
Weighted average exercise price | $ 9.21 | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value | $ 2,103 | $ 481 | $ 15,690 | |
Weighted-Average Remaining Contractual Life | ||||
Weighted average remaining contractual life | 8 years 7 months 6 days | 8 years | 8 years 8 months 12 days | 2 years 2 months 12 days |
Outstanding, Exercisable | 7 years 6 months | |||
Outstanding, Vested and expected to vest at end of period | 8 years 7 months 6 days | |||
Aggregate Intrinsic Value: | ||||
Beginning balance, aggregate intrinsic value | $ 16,287 | $ 8,160 | $ 3,656 | |
Beginning balance, aggregate intrinsic value | 8,187 | $ 16,287 | $ 8,160 | $ 3,656 |
Outstanding, Exercisable at end of period | 5,211 | |||
Outstanding, Vested and expected to vest at end of period | $ 8,180 |
Stock-Based Compensation (Issue
Stock-Based Compensation (Issued and Outstanding Option Details) (Details) - $ / shares | 12 Months Ended | |||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | Aug. 31, 2012 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Outstanding options | 4,176,500 | |||
Weighted average remaining contractual life | 8 years 7 months 6 days | 8 years | 8 years 8 months 12 days | 2 years 2 months 12 days |
Weighted average exercise price (in dollars per share) | $ 9.29 | $ 5.94 | $ 4.88 | $ 5.09 |
Exercisable options | 1,330,600 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 7.03 | |||
Under $5.00 [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Exercise price range minimum (in dollars per share) | $ 5 | |||
Outstanding options | 679,000 | |||
Weighted average remaining contractual life | 6 years 1 month 6 days | |||
Weighted average exercise price (in dollars per share) | $ 3.53 | |||
Exercisable options | 463,000 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 3.52 | |||
$5.00 - $6.99 [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Exercise price range minimum (in dollars per share) | 6.99 | |||
Exercise price range maximum (in dollars per share) | $ 5 | |||
Outstanding options | 637,000 | |||
Weighted average remaining contractual life | 7 years 6 months | |||
Weighted average exercise price (in dollars per share) | $ 6.54 | |||
Exercisable options | 412,000 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 6.59 | |||
$7.00 - $10.99 [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Exercise price range minimum (in dollars per share) | 10.99 | |||
Exercise price range maximum (in dollars per share) | $ 7 | |||
Outstanding options | 563,000 | |||
Weighted average remaining contractual life | 8 years 7 months 6 days | |||
Weighted average exercise price (in dollars per share) | $ 9.65 | |||
Exercisable options | 89,600 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 8.97 | |||
$11.00 - $13.46 [Member] | ||||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||||
Exercise price range minimum (in dollars per share) | 13.46 | |||
Exercise price range maximum (in dollars per share) | $ 11 | |||
Outstanding options | 2,297,500 | |||
Weighted average remaining contractual life | 9 years 7 months 6 days | |||
Weighted average exercise price (in dollars per share) | $ 11.66 | |||
Exercisable options | 366,000 | |||
Exercisable options, weighted average exercise price (in dollars per share) | $ 11.50 |
Stock-Based Compensation (Restr
Stock-Based Compensation (Restricted Stock Activity) (Details) - Restricted Stock [Member] - $ / shares | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Number of Shares | |||
Nonvested, Beginning balance | 293,333 | 46,667 | 13,750 |
Granted | 547,699 | 343,780 | 109,096 |
Vested | (208,532) | (97,114) | (76,179) |
Forfeited | 0 | 0 | 0 |
Nonvested, Ending balance | 632,500 | 293,333 | 46,667 |
Weighted Average Grant Date Fair Value (in dollars per share) | |||
Nonvested, beginning balance (in dollars per share) | $ 10.60 | $ 6.75 | $ 3.06 |
Granted | 11.17 | 11.34 | 6.41 |
Vested | 11.09 | 11.38 | 5.60 |
Forfeited | 0 | 0 | 0 |
Nonvested, ending balance (in dollars per share) | $ 10.93 | $ 10.60 | $ 6.75 |
Income Taxes (Schedule of Compo
Income Taxes (Schedule of Components of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Aug. 31, 2015 | May. 31, 2015 | Feb. 28, 2015 | Nov. 30, 2014 | Aug. 31, 2014 | May. 31, 2014 | Feb. 28, 2014 | Nov. 30, 2013 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Current: | |||||||||||
Federal | $ (4) | $ 4 | $ 0 | ||||||||
State | (111) | 111 | 0 | ||||||||
Total current income tax expense (benefit) | (115) | 115 | 0 | ||||||||
Deferred: | |||||||||||
Federal | 10,820 | 13,748 | 6,367 | ||||||||
State | 972 | 1,151 | 503 | ||||||||
Total deferred income tax expense | 11,792 | 14,899 | 6,870 | ||||||||
Income tax provision | $ (1,441) | $ (1,833) | $ 3,207 | $ 11,744 | $ 6,173 | $ 3,116 | $ 2,338 | $ 3,387 | $ 11,677 | $ 15,014 | $ 6,870 |
Income Taxes (Schedule of Recon
Income Taxes (Schedule of Reconciliation of Income Taxes) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Aug. 31, 2015 | May. 31, 2015 | Feb. 28, 2015 | Nov. 30, 2014 | Aug. 31, 2014 | May. 31, 2014 | Feb. 28, 2014 | Nov. 30, 2013 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Income Tax Disclosure [Abstract] | |||||||||||
Federal income tax at statutory rate | $ 10,105 | $ 14,915 | $ 5,594 | ||||||||
State income taxes, net of federal tax | 908 | 1,341 | 503 | ||||||||
Statutory depletion | (451) | (1,266) | (929) | ||||||||
Stock-based compensation | 92 | 0 | 1,911 | ||||||||
Nondeductible compensation | 850 | 125 | 0 | ||||||||
Other | 173 | (101) | (209) | ||||||||
Income tax provision | $ (1,441) | $ (1,833) | $ 3,207 | $ 11,744 | $ 6,173 | $ 3,116 | $ 2,338 | $ 3,387 | $ 11,677 | $ 15,014 | $ 6,870 |
Effective rate expressed as a percentage | 39.00% | 34.00% | 42.00% |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Thousands | Aug. 31, 2015 | Aug. 31, 2014 |
Deferred tax assets: | ||
Net operating loss carry-forward | $ 3,387 | $ 8,589 |
Stock-based compensation | 2,788 | 1,115 |
Statutory depletion | 2,652 | 2,194 |
Unrealized loss on commodity derivative | 0 | 70 |
Other | 192 | 4 |
Gross deferred tax assets | 9,019 | 11,972 |
Deferred tax liabilities: | ||
Basis of oil and gas properties | 18,433 | 33,409 |
Unrealized gain on commodity derivative | 593 | 0 |
Gross deferred tax liabilities | 19,026 | 33,409 |
Deferred tax liability, net | $ 10,007 | $ 21,437 |
Income Taxes (Narrative) (Detai
Income Taxes (Narrative) (Details) $ in Millions | Aug. 31, 2015USD ($) |
Operating Loss Carryforwards [Line Items] | |
Compensation expense | $ 12.1 |
Domestic Tax Authority [Member] | |
Operating Loss Carryforwards [Line Items] | |
Net operating loss | 21.3 |
Net operating loss carryforwards | $ 9.2 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015USD ($)adirectorshares | Aug. 31, 2014USD ($)ashares | Aug. 31, 2013USD ($)ashares | |
Related Party Transaction [Line Items] | |||
Number of directors | director | 3 | ||
HS Land & Cattle, LLC [Member] | |||
Related Party Transaction [Line Items] | |||
Rent expense | $ 180 | $ 180 | $ 130 |
Board of Directors Member [Member] | |||
Related Party Transaction [Line Items] | |||
Shares of restricted common stock (in shares) | shares | 0 | 15,883 | 31,454 |
Value of common stock | $ 0 | $ 106 | $ 105 |
Director [Member] | |||
Related Party Transaction [Line Items] | |||
Shares of restricted common stock (in shares) | shares | 0 | 40,435 | 22,202 |
Value of common stock | $ 0 | $ 313 | $ 91 |
Mineral acres leased (in acres) | a | 0 | 4,844 | 2,263 |
Royalty expense | $ 209 | $ 292 | $ 304 |
Other Commitments and Conting77
Other Commitments and Contingencies (Details) $ in Thousands | 1 Months Ended | 12 Months Ended |
Oct. 15, 2015USD ($) | Aug. 31, 2015USD ($)counterpartyoil_rig | |
Long-term Purchase Commitment [Line Items] | ||
Transport agreement number of counterparties | counterparty | 2 | |
Ensign United States Drilling [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Number of rigs under contracts | oil_rig | 1 | |
Expected future costs | $ 2,300 | |
Subsequent Event [Member] | Denver [Member] | ||
Long-term Purchase Commitment [Line Items] | ||
Monthly rent expense | $ 30 |
Other Commitments and Conting78
Other Commitments and Contingencies (Volume Commitments) (Details) bbl / yr in Thousands | Aug. 31, 2015bbl / dbbl / yr |
Commitments and Contingencies Disclosure [Abstract] | |
Remaining calendar year | bbl / d | 7,500 |
2,016 | 2,213 |
2,017 | 4,072 |
2,018 | 4,072 |
2,019 | 4,072 |
2,020 | 4,072 |
Thereafter | 1,860 |
Total | 20,361 |
Supplemental Schedule of Info79
Supplemental Schedule of Information to the Statements of Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Supplemental cash flow information: | |||
Interest paid | $ 2,817 | $ 989 | $ 995 |
Income taxes paid | 202 | 0 | 0 |
Non-cash investing and financing activities: | |||
Accrued well costs | $ 33,071 | $ 71,849 | $ 25,491 |
Assets acquired in exchange for common stock | 60,221 | 11,184 | 16,684 |
Asset retirement costs and obligations | $ 7,051 | $ 1,610 | $ 1,578 |
Unaudited Oil and Gas Reserve80
Unaudited Oil and Gas Reserves Information (Narrative) (Details) Boe in Thousands | 12 Months Ended | |||||
Aug. 31, 2015Boewell$ / bbl$ / Mcf | Aug. 31, 2014Boe$ / bbl$ / Mcf | Aug. 31, 2013Boe$ / bbl$ / Mcf | Aug. 31, 2015$ / MMBTU | Aug. 31, 2015 | Aug. 31, 2015$ / Mcf | |
Reserve Quantities [Line Items] | ||||||
Net cash flows, discount rate (percent) | 10.00% | |||||
Boe [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Revisions of previous estimates (Boe) | (2,513) | 591 | (681) | |||
Purchase of reserves in place (Boe) | 7,860 | 2,021 | 2,228 | |||
Extensions, discoveries, and other additions (Boe) | 23,696 | 17,357 | 2,395 | |||
Number of wells | 36 | |||||
Oil (Bbl) [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 53.27 | 89.48 | 86.40 | |||
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | (36.21) | 3.08 | ||||
Gas (Mcf) [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Price per unit used to prepare reserve estimates, based upon average prices | 5.03 | 4.40 | 3.28 | 3.28 | ||
Increase (decrease) in price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | (1.75) | 0.63 | ||||
Wattenberg Field [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Exploratory wells | well | 67 | |||||
Wattenberg Field [Member] | Boe [Member] | ||||||
Reserve Quantities [Line Items] | ||||||
Extensions, discoveries, and other additions (Boe) | 23,696 |
Unaudited Oil and Gas Reserve81
Unaudited Oil and Gas Reserves Information (Schedule of Net Ownership Interests in Estimated Quantities of Proved Developed and Undeveloped Oil and Gas Reserve Quantities and Changes During Fiscal Year) (Details) bbl in Thousands, Mcf in Thousands, Boe in Thousands | 12 Months Ended | |||||||
Aug. 31, 2015Boe$ / bbl$ / McfbblMcf | Aug. 31, 2014Boe$ / bbl$ / McfbblMcf | Aug. 31, 2013Boe$ / bbl$ / McfbblMcf | Aug. 31, 2015$ / bbl | Aug. 31, 2015$ / MMBTU | Aug. 31, 2015Boe | Aug. 31, 2015Mcf | Aug. 31, 2015$ / Mcf | |
Oil (Bbl) [Member] | ||||||||
Proved developed and undeveloped reserves: | ||||||||
Beginning Balance | bbl | 16,324 | 7,047 | 5,086 | |||||
Revisions of previous estimates | bbl | (1,699) | 83 | (194) | |||||
Purchase of reserves in place | bbl | 4,201 | 1,028 | 1,000 | |||||
Extensions, discoveries, and other additions | bbl | 11,465 | 9,142 | 1,576 | |||||
Sale of reserves in place | bbl | (629) | (35) | 0 | |||||
Production | bbl | (1,970) | (941) | (421) | |||||
Ending Balance | bbl | 27,692 | 16,324 | 7,047 | |||||
Proved developed reserves: | ||||||||
Proved developed reserves | bbl | 7,393 | 6,616 | 4,659 | |||||
Proved undeveloped reserves: | ||||||||
Proved undeveloped reserves | bbl | 20,299 | 9,708 | 2,388 | |||||
Price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | 89.48 | 86.40 | 53.27 | |||||
Increase in price per unit used to prepare reserve estimates, based upon average prices | $ / bbl | (36.21) | 3.08 | ||||||
Gas (Mcf) [Member] | ||||||||
Proved developed and undeveloped reserves: | ||||||||
Beginning Balance | 95,179 | 40,690 | 33,446 | |||||
Revisions of previous estimates | (4,889) | 3,047 | (2,924) | |||||
Purchase of reserves in place | 21,957 | 5,956 | 7,361 | |||||
Extensions, discoveries, and other additions | 73,392 | 49,289 | 4,915 | |||||
Sale of reserves in place | (4,337) | (56) | 0 | |||||
Production | (7,344) | (3,747) | (2,108) | |||||
Ending Balance | 173,958 | 95,179 | 40,690 | |||||
Proved developed reserves: | ||||||||
Proved developed reserves | 38,162 | 25,866 | 46,026 | |||||
Proved undeveloped reserves: | ||||||||
Proved undeveloped reserves | 57,017 | 14,824 | 127,932 | |||||
Price per unit used to prepare reserve estimates, based upon average prices | 5.03 | 4.40 | 3.28 | 3.28 | ||||
Increase in price per unit used to prepare reserve estimates, based upon average prices | $ / Mcf | (1.75) | 0.63 | ||||||
Boe [Member] | ||||||||
Proved developed and undeveloped reserves: | ||||||||
Balance (Boe) | Boe | 32,188 | 13,829 | 10,660 | |||||
Revisions of previous estimates (Boe) | Boe | (2,513) | 591 | (681) | |||||
Purchase of reserves in place (Boe) | Boe | 7,860 | 2,021 | 2,228 | |||||
Extensions, discoveries, and other additions (Boe) | Boe | 23,696 | 17,357 | 2,395 | |||||
Sales of reserves in place (Boe) | Boe | (1,352) | (44) | 0 | |||||
Production (Boe) | Boe | (3,194) | (1,566) | (773) | |||||
Balance (Boe) | Boe | 56,685 | 32,188 | 13,829 | |||||
Proved developed reserves: | ||||||||
Proved developed reserves (Boe) | Boe | 12,977 | 8,970 | 15,064 | |||||
Proved undeveloped reserves: | ||||||||
Proved undeveloped reserves (Boe) | Boe | 19,211 | 4,859 | 41,621 |
Unaudited Oil and Gas Reserve82
Unaudited Oil and Gas Reserves Information (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | Aug. 31, 2012 |
Oil and Gas Exploration and Production Industries Disclosures [Abstract] | ||||
Future cash inflows | $ 2,046,615 | $ 1,839,987 | $ 749,030 | |
Future production costs | (653,009) | (395,019) | (146,352) | |
Future development costs | (510,720) | (412,517) | (108,290) | |
Future income tax expense | (144,399) | (252,925) | (113,545) | |
Future net cash flows | 738,487 | 779,526 | 380,843 | |
10% annual discount for estimated timing of cash flows | (372,658) | (376,827) | (199,111) | |
Standardized measure of discounted future net cash flows | $ 365,829 | $ 402,699 | $ 181,732 | $ 102,505 |
Unaudited Oil and Gas Reserve83
Unaudited Oil and Gas Reserves Information (Schedule of Prices Used to Prepare Estimates of Oil and Gas Reserves) (Details) | Aug. 31, 2015$ / bbl | Aug. 31, 2015$ / MMBTU | Aug. 31, 2015$ / Mcf | Aug. 31, 2014$ / bbl$ / Mcf | Aug. 31, 2013$ / bbl$ / Mcf |
Oil (Bbl) [Member] | |||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||||
Price per unit used to prepare reserve estimates, based upon average prices | 53.27 | 89.48 | 86.40 | ||
Gas (Mcf) [Member] | |||||
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items] | |||||
Price per unit used to prepare reserve estimates, based upon average prices | 3.28 | 3.28 | 5.03 | 4.40 |
Unaudited Oil and Gas Reserve84
Unaudited Oil and Gas Reserves Information (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward] | |||
Standardized measure, beginning of year | $ 402,699 | $ 181,732 | $ 102,505 |
Sale and transfers, net of production costs | (98,486) | (86,808) | (38,569) |
Net changes in prices and production costs | (233,051) | 15,828 | (4,550) |
Extensions, discoveries, and improved recovery | 173,918 | 300,087 | 70,191 |
Changes in estimated future development costs | 10,002 | (20,817) | (6,006) |
Development costs incurred during the period | 4,957 | 15,000 | 5,106 |
Revision of quantity estimates | (38,340) | 4,589 | (14,214) |
Accretion of discount | 57,629 | 23,612 | 35,103 |
Net change in income taxes | 58,547 | (76,616) | (7,850) |
Divestitures of reserves | (19,234) | (925) | 0 |
Purchase of reserves in place | 56,795 | 47,017 | 40,016 |
Changes in timing and other | (9,607) | 0 | 0 |
Standardized measure, end of year | $ 365,829 | $ 402,699 | $ 181,732 |
Unaudited Quarterly Financial85
Unaudited Quarterly Financial Data (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Aug. 31, 2015 | May. 31, 2015 | Feb. 28, 2015 | Nov. 30, 2014 | Aug. 31, 2014 | May. 31, 2014 | Feb. 28, 2014 | Nov. 30, 2013 | Aug. 31, 2015 | Aug. 31, 2014 | Aug. 31, 2013 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||
Revenues | $ 32,559 | $ 26,033 | $ 23,713 | $ 42,538 | $ 36,253 | $ 25,672 | $ 23,028 | $ 19,266 | |||
Expenses | 44,919 | 29,102 | 25,417 | 27,783 | 20,744 | 14,413 | 13,550 | 12,048 | $ 127,221 | $ 60,755 | $ 26,678 |
Operating (loss) income | (12,360) | (3,069) | (1,704) | 14,755 | 15,509 | 11,259 | 9,478 | 7,218 | (2,378) | 43,464 | 19,545 |
Other income (expense) | 5,639 | (1,245) | 9,563 | 18,140 | 1,096 | (983) | (1,979) | 2,269 | 32,097 | 403 | (3,094) |
Income before income taxes | (6,721) | (4,314) | 7,859 | 32,895 | 16,605 | 10,276 | 7,499 | 9,487 | 29,719 | 43,867 | 16,451 |
Income tax provision (benefit) | (1,441) | (1,833) | 3,207 | 11,744 | 6,173 | 3,116 | 2,338 | 3,387 | 11,677 | 15,014 | 6,870 |
Net income | $ (5,280) | $ (2,481) | $ 4,652 | $ 21,151 | $ 10,432 | $ 7,160 | $ 5,161 | $ 6,100 | $ 18,042 | $ 28,853 | $ 9,581 |
Net income per common share: | |||||||||||
Basic (in dollars per share) | $ (0.05) | $ (0.02) | $ 0.05 | $ 0.27 | $ 0.13 | $ 0.09 | $ 0.07 | $ 0.08 | $ 0.19 | $ 0.38 | $ 0.17 |
Diluted (in dollars per share) | $ (0.05) | $ (0.02) | $ 0.05 | $ 0.26 | $ 0.13 | $ 0.09 | $ 0.07 | $ 0.08 | $ 0.19 | $ 0.37 | $ 0.16 |
Weighted average shares outstanding: | |||||||||||
Basic (in shares) | 105,084,651 | 104,234,519 | 89,903,288 | 79,008,719 | 77,771,916 | 77,176,420 | 76,203,938 | 73,674,865 | 94,628,665 | 76,214,737 | 57,089,362 |
Diluted (in shares) | 90,636,107 | 80,141,152 | 79,698,720 | 79,008,619 | 77,990,416 | 76,044,605 | 95,319,269 | 77,808,054 | 59,088,761 |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event [Member] - K.P. Kauffman Company, Inc. [Member] $ in Millions | Sep. 14, 2015USD ($)abbl / d |
Subsequent Event [Line Items] | |
Mineral acres, net | a | 4,300 |
Cash | $ 35 |
Issuance of shares | $ 4.4 |
Production of barrels of oil equivalent per day | bbl / d | 1,200 |