| Significant Accounting Policies [Text Block] | 3. Summary of significant accounting policies Fair Value Measurements The Company measures and discloses information about the fair value of its financial instruments by establishing a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three (3) broad levels. The fair value hierarchy gives the highest priority to quoted prices (unadjusted) in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three (3) levels of fair value hierarchy are: Level 1 — Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 — Inputs (other than quoted market prices included in Level 1) are either directly or indirectly observable for the asset or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life. Level 3 — Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date. Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model. Valuation of instruments includes unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities. Fair Value of Financial Instruments For certain of the Company’s financial instruments, including cash and cash equivalents, accounts receivable, other assets, and accounts payable, the fair values approximate carrying values due to the short-term maturities of these instruments. The carrying values of other assets and accrued expenses are also not recorded at fair value, but approximate fair values primarily due to their short-term nature. The carrying value of the Company’s notes payable also approximate fair value since the instruments bear market rates of interest. None of these instruments are held for trading purposes. Cash and Cash Equivalents The Company considers all highly-liquid debt instruments with original maturities of three and three months or less to be cash equivalents. The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). All accounts maintain FDIC coverage of up to $250,000 per institution. As of June 30, 2015 and December 31, 2014, the Company had $8,000 and $0, respectively, of cash and cash equivalents in excess of its FDIC coverage. Accounts Receivable Accounts receivable consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production and amounts owed from interest owners of the Company’s operated wells. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. The Company reviews accounts receivable periodically and reduces the carrying amount by a valuation allowance that reflects its best estimate of the amount that may not be collectible. There was no reserve for bad debts as of June 30, 2015 or December 31, 2014. Derivative Activities The Company utilized oil and natural gas derivative contracts to mitigate its exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts are valued using level 2 inputs and have historically consisted of options, in the form of price floors or collars. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company does not apply hedge accounting to its oil and natural gas derivative contracts and accordingly the changes in the fair value of these instruments are recognized in the consolidated statements of operations in the period of change. The Company’s derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, Company management believes the benefits of stable and predictable cash flow are more important. Among these benefits are more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long-term projects requiring substantial committed capital, smoother and more efficient execution of our ongoing development drilling and production enhancement programs, more consistent returns on invested capital and better access to bank and other capital markets. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. Realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative gains or (losses) in the accompanying condensed consolidated statements of operations. Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its oil and natural gas producing activities whereby all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and natural gas property acquisitions are capitalized. All costs related to production, general corporate overhead or similar activities are expensed as incurred. Proved properties are amortized using the units of production method (“UOP”). The UOP calculation, in its simplest terms, multiplies the percentage of estimated proved reserves produced at year end by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop reserves) and asset retirement costs that are not already included in oil and natural gas property, less related salvage value. The cost of unproved properties and properties under development are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed in service. Geological and geophysical costs not associated with specific properties are recorded to proved properties. Unproved properties and properties under development are reviewed for impairment at least quarterly. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. As of June 30, 2015 and December 31, 2014, no unproved properties or properties under development were included in the oil and natural gas properties of the accompanying condensed consolidated financial statements. Proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income. For the three and six months ended June 30, 2015 no gain or loss from the sale or disposition of oil and natural gas properties occurred, this is a decrease of $316,000 compared to the same time period in 2014. Under the full-cost method of accounting, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and natural gas reserves, discounted at 10 percent per annum based on industry standards and adjusted for cash flow hedges. Estimated future net cash flows exclude future cash outflows associated with settling accrued asset retirement obligations. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the accompanying condensed consolidated statements of operations. For the three and six months ended June 30, 2015 and 2014 no impairment charge occurred. Other Property and Equipment Other property and equipment, which includes buildings, field equipment, vehicles, and office equipment, is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Vehicles and office equipment are generally depreciated over a useful life of five or six years, field equipment is generally depreciated over a useful life of ten years and buildings are generally depreciated over a useful life of twenty years. Impairment of Long-Lived Assets The Company assesses the impairment of long-lived assets when circumstances indicate that the carrying value may not be recoverable. The Company determines if impairment has occurred through adverse changes. When it is determined that the estimated future net cash flows of an asset will not be sufficient to recover its carrying amount, an impairment loss must be recorded to reduce the carrying amount to its estimated fair value. For the three and six months ended June 30, 2015, and 2014 no circumstances indicated an unrecoverable carrying value of the long-lived assets. Goodwill Goodwill was generated as part of the CTO (CoreTerra Operating LLC) acquisition during the year ended December 31, 2011 and represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition. Goodwill is not amortized; rather, it is tested for impairment annually and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expenses. For the three and six months ended June 30, 2015, and 2014 no impairment charge occurred. Asset Retirement Obligations The Company records the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the Company capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations are valued using level 3 inputs and relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties. Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates. Revenue Recognition and Natural Gas Imbalances The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells. The Company will also enter into physical contract sale agreements through its normal operations. These contracts are not considered derivative contracts by the Company in accordance with the normal purchases and normal sales provision of ASC 815-10-15. Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances. Net Loss Per Common Share Basic net loss per common share is computed by dividing the net loss attributable to shareholders by the weighted average number of common shares outstanding during the period. Diluted net loss per common share is calculated in the same manner, but also considers the impact to net loss and common shares for the potential dilution from convertible preferred stock and warrants. For the six months ended June 30, 2015, there were 4,898,940 of potentially dilutive shares that were not included in the diluted weighted average common shares as the Company had a net loss for the period. For the six months ended June 30, 2014, there were 4,319,500 potentially dilutive shares and no outstanding potentially antidilutive shares considered in the diluted weighted average common shares. Stock-Based Compensation The Company measures and recognizes compensation expense in the Company’s consolidated statements of operations for all share-based payment awards made to the Company’s employees, directors and consultants including employee stock options, non-vested equity stock and equity stock units, and employee stock purchase grants. Stock-based compensation expense is measured at the grant date, based on the estimated fair value of the award, reduced by an estimate of the annualized rate of expected forfeitures, and is recognized as an expense over the employees’ expected requisite service period, generally using the straight-line method. In addition, the benefits of tax deductions in excess of recognized compensation expense are reported as a financing cash flow. The Company’s forfeiture rate represents the historical rate at which the Company’s stock-based awards were surrendered prior to vesting. Forfeitures are estimated at the time of grant and revised on a cumulative basis, if necessary, in subsequent periods if actual forfeitures differ from those estimates. During the three and six months ended June 30, 2015 and 2014, the Company incurred a stock based compensation expense, of $0 and $13,000 respectively, related to stock grant issuances and is included in the accompanying consolidated statement of operations in general and administrative expenses. |
