Note 2 - Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2016

The consolidated financial statements include the accounts of our wholly owned and majority owned subsidiaries. Intercompany transactions and balances have been eliminated. Management evaluates its investments on an individual basis for purposes of determining whether or not consolidation is appropriate.

Basic and Diluted Earnings (loss) Per Share

Basic and Diluted Earnings (Loss) Per Share

Earnings per share is calculated in accordance with the ASC 260-10, Earnings Per Share. Basic earnings-per-share is based upon the weighted average number of common shares outstanding. Diluted earnings-per-share is based on the assumption that all dilutive convertible notes, stock options and warrants were converted or exercised. Dilution is computed by applying the treasury stock method. Under this method, options and warrants are assumed to be exercised at the beginning of the period (or at the time of issuance, if later), and as if funds obtained thereby were used to purchase common stock at the average market price during the period.

The following potentially dilutive shares were excluded from the shares used to calculate diluted earnings per share as their inclusion would be anti-dilutive.

	June 30,
	2016	2015
Options	5,825,000	1,325,000
Warrants	9,279,992	16,202,992
Convertible notes	2,000,000	2,000,000
Total	17,104,992	19,527,992

Management Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. Significant estimates reflected in the consolidated financial statements include, but are not limited to, amortization and depletion allowances, the recoverability of the carrying amount and estimated useful lives of long-lived assets, asset retirement obligations, the valuation of equity instruments issued in connection with financing transactions and share-based compensation, and assumptions used in valuing derivative liabilities. Changes in facts and circumstances may result in revised estimates. Actual results could differ from those estimates.

Full Cost Method of Accounting For Oil and Gas Properties

Full Cost Method of Accounting for Oil and Gas Properties

The Company has elected to utilize the full cost method of accounting for its oil and gas activities. In accordance with the full cost method of accounting, the Company capitalizes all costs associated with acquisition, exploration and development of oil and natural gas reserves, including leasehold acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties and costs of drilling of productive and non-productive wells into the full cost pool on a country by country basis. Capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves, are amortized on the unit-of-production method using estimates of proved reserves once proved reserves are determined to exist.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method. The equivalent unit-of-production rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter then applying such amount to capitalized oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

Full Cost Ceiling Test

Oil and gas properties without estimated proved reserves are not amortized until proved reserves associated with the properties can be determined or until impairment occurs. At the end of each reporting period, the unamortized costs of oil and gas properties are subject to a "ceiling test" which limits capitalized costs to the sum of the estimated future net revenues from proved reserves, discounted at 10% per annum to present value, based on current economic and operating conditions, adjusted for related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

The estimated future net revenues used in the ceiling test are calculated using average quoted market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices used in the ceiling test computation do not include the impact of derivative instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment.

The Company assesses oil and gas properties at least quarterly to ascertain whether impairment has occurred. In assessing impairment, the Company considers factors such as historical experience and other data such as primary lease terms of the property, average holding periods of unproved property, and geographic and geologic data. Through June 30, 2016, the Company has not experienced any impairment of its capitalized oil and gas properties.

The Company recorded depletion expense of $10,709 and $22,322 for the six months ended June 30, 2016 and 2015, respectively.

Proceeds from the sale of oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. Through June 30, 2016, the Company has not had any sales of oil and gas properties that significantly alter that relationship.

Asset Retirement Obligation

The Company accounts for its future asset retirement obligations ("ARO") by recording the fair value of the liability during the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an ARO is included in proven oil and gas properties in the balance sheets. The ARO consists of costs related to the plugging of wells, removal of facilities and equipment, and site restoration on its oil and gas properties. The asset retirement liability is accreted to operating expense over the useful life of the related asset. As of June 30, 2016 and December 31, 2015, the Company had an ARO of $97,138 and $92,512, respectively.

Oil and Gas Revenue

Revenues are recognized when hydrocarbons have been delivered, the customer has taken title and collection is reasonably assured.

Share-based Compensation, Option and Incentive Plans Policy

Share-Based Compensation

The Company periodically issues stock options and warrants to employees and non-employees in capital raising transactions, for services and for financing costs. The Company accounts for share-based payments under the guidance as set forth in the Share-Based Payment Topic of the FASB Accounting Standards Codification, which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees, officers, directors, and consultants, including employee stock options, based on estimated fair values. The Company estimates the fair value of share-based payment awards to employees and directors on the date of grant using an option-pricing model, and the value of the portion of the award that is ultimately expected to vest is recognized as expense over the required service period in the Company's Statements of Operations. The Company accounts for stock option and warrant grants issued and vesting to non-employees in accordance with the authoritative guidance where the value of the stock compensation is based upon the measurement date as determined at either a) the date at which a performance commitment is reached, or b) the date at which the necessary performance to earn the equity instruments is complete. Stock-based compensation is based on awards ultimately expected to vest and is reduced for estimated forfeitures. Forfeitures are estimated at the time of grant and revised, as necessary, in subsequent periods if actual forfeitures differ from those estimates.

Fair Value Measurement, Policy

Fair Value Measurements

The Company applies the provisions of ASC 820-10, Fair Value Measurements and Disclosures. ASC 820-10 defines fair value, and establishes a three-level valuation hierarchy for disclosures of fair value measurement that enhances disclosure requirements for fair value measures. The three levels of valuation hierarchy are defined as follows:

· Level 1 inputs to the valuation methodology are quoted prices for identical assets or liabilities in active markets.

· Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

· Level 3 inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents and current liabilities, including notes payable and convertible notes, each qualify as financial instruments and are a reasonable estimate of their fair values because of the short period of time between the origination of such instruments and their expected realization and their current market rate of interest.

The Company uses Level 2 inputs for its valuation methodology for the warrant derivative liabilities as their fair values were determined by using a probability weighted average Black-Scholes-Merton pricing model based on various assumptions. The Company's derivative liabilities are adjusted to reflect fair value at each period end, with any increase or decrease in the fair value being recorded in results of operations as adjustments to fair value of derivatives.

Concentrations

The Company maintains cash balances at a bank in California. The account is insured by the Federal Deposit Insurance Corporation up to $250,000 per institution. At June 30, 2016 and December 31, 2015, the Company did not have amounts on deposit that exceeded the FDIC-insured limits.

The future results of the Company's oil and natural gas operations will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty.

One customer accounts for 100% of oil sales for the six months ended June 30, 2016 and 2015. The Company's oil and gas properties are located in Illinois.

Derivative Financial Instruments

The Company evaluates its financial instruments to determine if such instruments are derivatives or contain features that qualify as embedded derivatives. For derivative financial instruments that are accounted for as liabilities, the derivative instrument is initially recorded at its fair value and is then re-valued at each reporting date, with changes in the fair value reported in the statements of operations. The Company uses a probability weighted average Black-Scholes-Merton model to value the derivative instruments. The classification of derivative instruments, including whether such instruments should be recorded as liabilities or as equity, is evaluated at the end of each reporting period. Derivative instrument liabilities are classified in the balance sheet as current or non-current based on whether or not net-cash settlement of the derivative instrument could be required within 12 months of the balance sheet date.

Recently Issued Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers. ASU 2014-09 is a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining revenue recognition. ASU 2014-09 will require that companies recognize revenue based on the value of transferred goods or services as they occur in the contract. The ASU also will require additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted only in annual reporting periods beginning after December 15, 2016, including interim periods therein. Entities will be able to transition to the standard either retrospectively or as a cumulative-effect adjustment as of the date of adoption. The Company is in the process of evaluating the impact of ASU 2014-09 on the Company's financial statements and disclosures.

In February 2016, the FASB issued Accounting Standards Update (ASU) No. 2016-02, Leases. ASU 2016-02 requires a lessee to record a right of use asset and a corresponding lease liability on the balance sheet for all leases with terms longer than 12 months. ASU 2016-02 is effective for all interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Company is in the process of evaluating the impact of ASU 2016-02 on the Company's financial statements and disclosures.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. ASU 2014-15 requires management to perform interim and annual assessments of an entity's ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity's ability to continue as a going concern. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and interim periods thereafter. Early adoption is permitted. The Company is currently evaluating the impact of the adoption of ASU 2014-15 on the Company's financial statements and disclosures.

Other recent accounting pronouncements issued by the FASB, including its Emerging Issues Task Force, the American Institute of Certified Public Accountants, and the Securities and Exchange Commission did not or are not believed by management to have a material impact on the Company's present or future financial statements.

Eos Petro, Inc. 10-Q