Annual report pursuant to Section 13 and 15(d)

Summary of Significant Accounting Policies (Policies)

Summary of Significant Accounting Policies (Policies)
12 Months Ended
Dec. 31, 2018
Summary Of Significant Accounting Policies  
Basis of Presentation

The accompanying consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for consolidated financial information and with the instructions to Form 10-K as promulgated by the Securities and Exchange Commission (the “SEC”). Accordingly, these consolidated financial statements include all of the disclosures required by generally accepted accounting principles for complete consolidated financial statements.

Basis of Consolidation

The financial statements presented herein reflect the consolidated financial results of the Company and its wholly owned subsidiaries, Viking Oil & Gas (Canada) ULC, a Canadian corporation formed to provide a base of operations for properties in Canada; Mid-Con Petroleum, LLC, Mid-Con Drilling, LLC, and Mid-Con Development, LLC, which were all formed to provide a base of operations for properties in the Central United States; and Petrodome Energy, LLC, Ichor Energy Holdings, LLC, Ichor Energy, LLC, Ichor Energy (TX), LLC, and Ichor Energy (LA), LLC,which provides a base of operations to facilitate property acquisitions in Texas, Louisiana and Mississippi. All significant intercompany transactions and balances have been eliminated.

Use of Estimates in the Preparation of Financial Statements

The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions that affect the reported amounts and timing of revenues and expenses, the reported amounts and classification of assets and liabilities, and disclosure of contingent assets and liabilities.Significant areas requiring the use of management estimates relate to impairment of long-lived assets, stock-based compensation, asset retirement obligations, business combinations, derivatives and the determination of expected tax rates for future income tax recoveries.


The estimates of proved, probable and possible oil and gas reserves are used as significant inputs in determining the depletion of oil and gas properties and the impairment of proved and unproved oil and gas properties. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks.Actual results could differ from the estimates and assumptions utilized.

Financial Instruments

Accounting Standards Codification, “ASC” Topic 820-10, “Fair Value Measurement” requires disclosure of the fair value of financial instruments held by the Company. ASC Topic 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 measurement. The carrying amounts reported in the consolidated balance sheets for accounts receivable, other receivable – related party, accrued expenses and other current liabilities, accounts payable, derivative liabilities and assets, amount due to directors, 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 three levels of valuation hierarchy are defined as follows:


  · Level 1: inputs to the valuation methodology are quoted prices (unadjusted) 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.


Assets and liabilities measured at fair value as of December 31, 2018 are classified below based on the three fair value hierarchy described above:



Quoted Prices in Active Markets for Identical


(Level 1)






(Level 2)


Significant Unobservable


(Level 3)


Total Gains


Financial Assets                        
Commodity Derivative   $ -     $ 681,776     $ -     $ 926,802  
    $ -     $ 681,776     $ -     $ 926,802  
Financial liabilities                                
Commodity Derivative             2,531,718       -       (2,531,718 )
    $ -     $ 2,531,718     $ -     $ (2,531,718 )


Assets and liabilities measured at fair value as of December 31, 2017, are classified below based on the three-level fair value hierarchy described above:



Quoted Prices in Active Markets for Identical Assets

(Level 1)


Significant Other Observable Inputs

(Level 2)


Significant Unobservable


(Level 3)


Total Gains


Financial Assets                        
Long term investment   $ -     $ -     $ -     $ 1,446  
    $ -     $ -     $ -     $ 1,446  
Financial liabilities                                
Derivative liabilities   $ -     $ -     $ 807,762     $ 232,840  
Commodity Derivative     -       245,026       -       (183,965 )
    $ -     $ 245,026     $ 807,762     $ 48,875  


The Company had a long-term investment which consisted of 1,437,500 common shares of Tanager Energy Inc., as of December 31, 2016. During the three months ended March 31, 2017, the Company sold these shares. The change in the fair value of this investment that has been recognized as an unrealized gain in other comprehensive income on the statement of operations and comprehensive loss was $1,446 for the year ended December 31, 2017.


The Company had commodity financial derivatives in place at December 31, 2018 and 2017. The Company does not designate its commodities derivative instruments as hedges and therefore does not apply hedge accounting. Changes in fair value of derivative instruments subsequent to the initial measurement are recorded as change in fair value on derivative liability, in other income (expense). The estimated fair value amounts of the Company’s commodity derivative instruments have been determined at discrete points in time based on relevant market information which resulted in the Company classifying such derivatives as Level 2. Although the Company’s commodity derivative instruments are valued using public indices, as well as the Black-Sholes model, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange.


Although the Company is exposed to credit risk to the extent of nonperformance by the counterparties to these derivative contracts, the Company does not anticipate such nonperformance and monitors the credit worthiness of its counterparties on an ongoing basis.


The Company has entered into certain commodity derivative instruments containing swaps and collars, which are effective in mitigating commodity price risk associated with a portion of its future monthly natural gas and crude oil production and related cash flows.


In a commodities swap agreement, the Company trades the fluctuating market prices of oil or natural gas at specific delivery points over a specified period, for fixed prices. As a producer of oil and natural gas, the Company holds these commodity derivatives to protect the operating revenues and cash flows related to a portion of its future natural gas and crude oil sales from the risk of significant declines in commodity prices, which helps reduce exposure to price risk and improves the likelihood of funding its capital budget.If the price of a commodity rises above what the Company has agreed to receive in the swap agreement, the amount that it agreed to pay the counterparty is expected to be offset by the increased amount it received for its production.


The Company has entered into collar agreements related to oil and gas production with established floors and ceilings, which upon settlement, if the current market price of the commodity is below the floor, the Company receives the difference. If the current market price of the commodity is above the ceiling the Company pays the excess over the ceiling price.


The derivative assets were $681,776 as of December 31, 2018, and the derivative liabilities were $2,531,718 and $1,052,788 as of December 31, 2018 and 2017 respectively. The change in the fair value of the derivative assets and liabilities for the year ended December 31, 2018 consisted of an increase of $926,802 associated with existing commodity derivatives and a decrease of $2,531,718 associated with new commodity derivatives related to the acquisition accomplished on December 28, 2018 and a loss recognized in the statement of operations and comprehensive loss in the amount of $1,604,916.The change in the fair value of the derivative assets and liabilities for the year ended December 31, 2017 consisted of an increase of $183,965 associated with commodity derivatives, and a decrease in derivative liabilities of $232,840 associated with warrants and the conversion features of new convertible debt, and a reduction of $35,232 associated with the satisfaction of certain convertible debt resulting in a gain recognized in the statement of operations and comprehensive loss in the amount of $48,875.


The table below is a summary of the Company’s commodity derivatives as of December 31, 2018:


Natural Gas   Period   Average MMBTU per Month     Fixed Price per MMBTU  
Swap   Dec-18 to Dec-22     118,936     $ 2.715  
Crude Oil   Period   Average BBL per Month     Price per BBL  
Swap   Dec-18 to Dec- 22     24,600     $ 50.85  
Swap   Dec-17 to Dec-19     1,400     $ 54.77  
Swap   Jan-20 to Jun-20     1,400     $ 52.71  
Collar   Dec-17 to Jun-20     4,000     $ 55.00 / $72.00  
Collar   Sep-17 to Sep-19     1,100     $ 47.00 / $54.10  


The tables below summarize the Company’s commodity derivatives and the effect of master netting arrangements on the presentation in the Company’s consolidated balance sheets as of December 31, 2018:





    Offsets on the Consolidated Balance Sheet    



Derivative assets                  
Fair value of derivative contracts   $ 880,700     $ (198,924 )   $ 681,776  
Derivative liabilities                        
Fair value of derivative contracts   $ 2,730,642     $ (198,924 )   $ 2,531,718  
Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid investment securities that have original maturities of three months or less. At December 31, 2018 and 2017, the Company has cash deposits in excess of FDIC insured limits in the amounts of $3,045,695 and $5,372,818 respectively.


Restricted cash in the amount of $5,199,103 as of December 31, 2017 represents cash provided through funding for the Petrodome acquisition, restricted for drilling and exploration at that time.

Accounts receivable

Accounts receivable consist of oil and gas receivables.. The Company evaluates these accounts receivable for collectability and, when necessary, records allowances for expected unrecoverable amounts. The Company has recorded an allowance for doubtful accounts of $217,057 at December 31, 2018.

Prepaid equity based compensation

Prepaid equity-based expenses represent amounts paid in advance through the issuance of restricted shares of stock, for future contractual benefits to be received.These expenses paid in advance are recorded as prepaid equity-based compensation as a component of “Stockholders’ Equity” and then amortized to the statements of operations and comprehensive loss over the life of the contract using the straight-line method.At December 31, 2018 and December 31, 2017, the balances of the prepaid equity-based compensation were comprised of the following:



December 31,



December 31,


In February 2017, a one-year consulting agreement for services related to investor relations, market exposure and content development for a total amount of $44,160.   $ -     $ 6,412  
In April 2017, a one-year consulting agreement comprised of four quarterly incremental installments for services related to analysis of potential oil and gas acquisitions, for an initial quarterly amount of $40,250, a second installment of $28,000 in July 2017, and a third installment of $55,000 in January 2018.     -       5,415  
    $ -     $ 11,827  
Oil and Gas Properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties. Under this method of accounting, all costs associated with acquisition, exploration and development of oil and gas reserves, including directly related overhead costs, are capitalized. General and administrative costs related to production and general overhead are expensed as incurred.


All 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. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in operations. 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 included in loss from operations before income taxes and the adjusted carrying amount of the unproved properties is amortized on the unit-of-production method.


Depreciation, depletion and amortization expense utilizing the unit-of-production method for the Company’s oil and gas properties for the years ended December 31, 2018 and 2017 were as follows:


Oil and Gas Properties by Geographical Cost Center
    Years ended,  
    December 31,  
Cost Center   2018     2017  
Canada   $ 21,387     $ 66,454  
United States     1,623,306       440,691  
    $ 1,644,693     $ 507,145  
Limitation on Capitalized Costs

Under the full-cost method of accounting, we are required, at the end of each reporting date, to perform a test to determine the limit on the book value of our oil and natural gas properties (the “Ceiling” test). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the Ceiling, this excess or impairment is charged to expense. The expense may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of:


(a) the present value, discounted at 10 percent, and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month hedging arrangements pursuant to SAB 103, less 2) estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, plus


(b) the cost of properties not being amortized; plus


(c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized, net of


(d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties.


The Company did not recognize an impairment loss on oil and gas properties for the years ended December 31, 2018 and 2017, respectively.

Oil and Gas Reserves

Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof, including evaluations and extrapolations of well flow rates and reservoir pressure. Estimates by different engineers often vary sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using recent prices of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices.

Income (loss) per Share

Basic income (loss) per share is computed by dividing the net income (loss) by the weighted-average number of common shares outstanding during the period. Diluted net income (loss) per share is computed by dividing the net income (loss) by the weighted-average number of common shares and, adjusted by any effects of warrants and options outstanding, if dilutive, that may add to the number of common shares during the period. At December 31, 2018 there were approximately 183,313,800common stock equivalents that were anti-dilutive.At December 31, 2017, there were 31,503,126 common stock equivalents that were not dilutive due to the market price being at or lower than the corresponding exercise price.

Revenue Recognition

On January 1, 2018, the Company adopted ASU 2014-09, “Revenue from Contracts with Customers (ASC 606),” using the modified retrospective method. Adoption of the new revenue standard had no impact on the Company’s consolidated balance sheet, results of operations, equity or cash flows as of the adoption date.


Sales of crude oil, natural gas, and natural gas liquids (NGLs) are included in revenue when production is sold to a customer in fulfillment of performance obligations under the terms of agreed contracts. Performance obligations primarily comprise delivery of oil, gas, or NGLs at a delivery point, as negotiated within each contract. Each barrel of oil, million BTU (MMBtu) of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, the Company’s right to payment, and transfer of legal title.In each case, the time between delivery and when payments are due is not significant.


The following table disaggregates the Company’s revenue by source for the years emded December 31, 2018 and 2017:


    Years Ended December 31,  
    2018     2017  
Oil   $ 7,777,100     $ 1,929,875  
Natural gas and Natural gas liquids     190,872       52,143  
    $ 7,967,972     $ 1,982,018  
Income Taxes

The Company accounts for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the consolidated financial statements. Under this method, the Company determines deferred tax assets and liabilities on the basis of the differences between the consolidated financial statements and the tax basis of assets and liabilities by using estimated tax rates for the year in which the differences are expected to reverse.


The Company recognizes deferred tax assets and liabilities to the extent that we believe that these assets and/or liabilities are more likely than not to be realized.In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax planning strategies, and results of recent operations. If we determine that the Company would be able to realize our deferred tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.


In assessing the realizability of its deferred tax assets and liabilities, management evaluated whether it is more likely than not that some portion or all of its deferred tax assets and liabilities will be realized. As of December 31, 2017, based on all the available evidence, management determined that it was more likely than not that a deferred tax liability of $910,827 would be fully realized.During the year ended December 31, 2018, the Company incurred a net loss, which created a decrease in its deferred tax liability with a corresponding income tax benefit in the amount of $910,827.

Stock-Based Compensation

The Company may issue stock options to employees and stock options or warrants to non-employees in non-capital raising transactions for services and for financing costs.The cost of stock options and warrants issued to employees and non-employees is measured on the grant date based on the fair value. The fair value is determined using the Black-Scholes option pricing model. The resulting amount is charged to expense on the straight-line basis over the period in which the Company expects to receive the benefit, which is generally the vesting period.


The fair value of stock options and warrants is determined at the date of grant using the Black-Scholes option pricing model. The Black-Scholes option model requires management to make various estimates and assumptions, including expected term, expected volatility, risk-free rate, and dividend yield. The expected term represents the period of time that stock-based compensation awards granted are expected to be outstanding and is estimated based on considerations including the vesting period, contractual term and anticipated employee exercise patterns. Expected volatility is based on the historical volatility of the Company’s stock. The risk-free rate is based on the U.S. Treasury yield curve in relation to the contractual life of stock-based compensation instrument. The dividend yield assumption is based on historical patterns and future expectations for the Company dividends.


During the year ended December 31, 2018, the Company granted 28,996,906 fully vested warrants to purchase common stock.The Company used the following Black-Scholes assumptions in arriving at the fair value of warrants recorded as stock-based compensation expense in the amount of $653,419 and warrants recorded as debt discount in the amount of $1,716,039.


Expected Life in Years     5.0  
Risk-free Interest Rates   2.55% to 2.94 %
Volatility   291% to 297 %
Dividend Yield     0 %


At December 31, 2018, there were no unrecognized compensation cost related to unvested warrants expected to be recognized in the future.


The following table represents stock warrant activity as of and for the year ended December 31, 2018:



Number of











Contractual Life





Warrants Outstanding – December 31, 2017     27,440,626       0.27     8.2 years       -  
Granted     28,821,690       0.25     4.7 years       -  
Exercised     (1,440,626 )     -       -       -  
Forfeited/expired/cancelled     -               -       -  
Warrants Outstanding – December 31, 2018     54,821,690     $ 0.26     6.0 years     $ -  
Outstanding Exercisable – December 31, 2017     27,440,626     $ 0.27     8.2 years     $ -  
Outstanding Exercisable – December 31, 2018     54,821,690     $ 0.26     6.0 years     $ -  
Impairment of long-lived assets

In accordance with ASC 360, “Accounting for the Impairment or Disposal of Long-Lived Assets”, the Company is required to review its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable through the estimated undiscounted cash flows expected to result from the use and eventual disposition of the assets. Whenever any such impairment exists, an impairment loss will be recognized for the amount by which the carrying value exceeds the fair value.


Assets are grouped and evaluated at the lowest level for their identifiable cash flows that are largely independent of the cash flows of other groups of assets. The Company considers historical performance and future estimated results in its evaluation of potential impairment and then compares the carrying amount of the asset to the future estimated cash flows expected to result from the use of the asset. If the carrying amount of the asset exceeds estimated expected undiscounted future cash flows, the Company measures the amount of impairment by comparing the carrying amount of the asset to its fair value. The estimation of fair value is generally determined by using the asset’s expected future discounted cash flows or market value. The Company estimates fair value of the assets based on certain assumptions such as budgets, internal projections, and other available information as considered necessary. There is no impairment of long-lived assets during the years ended December 31, 2018 and 2017.

Foreign Currency Exchange

An entity’s functional currency is the currency of the primary economic environment in which it operates, normally that is the currency of the environment in which the entity primarily generates and expends cash. Management’s judgment is essential to determine the functional currency by assessing various indicators, such as cash flows, sales price and market, expenses, financing and inter-company transactions and arrangements. The functional currency of the parent company is the U.S. Dollar. The reporting currency of the Company is the U.S. Dollar. The Company has oil and gas operations in Alberta, Canada in which the Canadian Dollar (“CAD” or “CS” herein) is the primary economic environment. The reporting currency of these consolidated financial statements is the U.S. Dollar.


For financial reporting purposes, the operational results of the Company’s oil and gas operations in Canada are prepared using the CAD, and are translated into the Company’s reporting currency, the U.S. Dollar. Revenue and expenses applicable to the oil and gas operations in Alberta, Canada are translated using average rates prevailing during each reporting period. Gains or losses resulting from the settlement of foreign currency transactions are recorded as a separate component of accumulated other comprehensive income in stockholders’ equity when realized. There have been no settlement transactions that resulted in the recognition of a foreign currency exchange gain or loss during the years ended December 31, 2018 and 2017.

Derivative Liability

We review the terms of convertible debt issues to determine whether there are embedded derivative instruments, including embedded conversion options, which are required to be bifurcated and accounted for separately as derivative financial instruments. In circumstances where the host instrument contains more than one embedded derivative instrument, including the conversion option, that is required to be bifurcated, the bifurcated derivative instruments are accounted for as a single, compound derivative instrument


Bifurcated embedded derivatives are initially recorded at fair value and are then revalued at each reporting date with changes in the fair value reported as non-operating income or expense. When the equity or convertible debt instruments contain embedded derivative instruments that are to be bifurcated and accounted for as liabilities, the total proceeds received are first allocated to the fair value of all the bifurcated derivative instruments. The remaining proceeds, if any, are then allocated to the host instruments themselves, usually resulting in those instruments being recorded at a discount from their face value. The discount from the face value of the convertible debt, together with the stated interest on the instrument, is amortized over the life of the instrument through periodic charges to interest expense.


The Company has evaluated the terms and conditions of certain of its warrants which included “down round” features. . The warrants did not meet the definition of “indexed to a company’s own stock” due to the down round protection feature. Therefore, the warrants required liability classification. The Company initially and subsequently measure the warrants at fair value, with changes in fair value recognized in earnings. On January 1, 2018, the Company adopted ASU 2017-11, Derivatives and Hedging (Topic 815), and increased beginning retained earnings in the amount of $807,762 (see Note 1 (s).

Accounting for Asset Retirement Obligations

Asset retirement obligations (“ARO”) primarily represent the estimated present value of the amount the Company will incur to plug, abandon and remediate its producing properties at the projected end of their productive lives, in accordance with applicable federal, state and local laws. The Company determined its ARO by calculating the present value of estimated cash flows related to the obligation. The retirement obligation is recorded as a liability at its estimated present value as of the obligation’s inception, with an offsetting increase to proved properties.


The following table describes the changes in the Company’s asset retirement obligations for the years ended December 31, 2017 and 2016:



Year ended December 31,



Year ended December 31,


Asset retirement obligation – beginning   $ 3,096,263     $ 833,017  
Oil and gas purchases     1,898,019       2,205,171  
Adjustments through disposals and settlements     (666,840 )     -  
Accretion expense     86,023       58,075  
Asset retirement obligation – ending   $ 4,413,465     $ 3,096,263  
Undistributed Revenues and Royalties

The Company records a liability for cash collected from oil and gas sales that have not been distributed. The amounts get distributed in accordance with the working interests of the respective owners.

Recently Accounting Pronouncements

As of December 31, 2018, and through the date of this filing, there were several new accounting pronouncements issued by the Financial Accounting Standards Board. Each of these pronouncements, as applicable, has been or will be adopted by the Company. Management does not believe the adoption of any of these accounting pronouncements has had or will have a material impact on the Company’s consolidated financial statements.The Company will monitor these emerging issues to assess any potential future impact on its financial statements.


ASU Update 2014-09, “Revenue from Contracts with Customers (Topic 606),” converged guidance on recognizing revenue in contracts with customers on an effective date after December 31, 2017.The ASU outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers which supersedes current revenue recognition guidance, including most industry-specific guidance. The guidance provides that an entity recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance also requires 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.The Company adopted Topic 606 as of January 1, 2018, using the modified retrospective transition method. Under the modified retrospective method, the Company would recognize the cumulative effect of initially applying the standard as an adjustment to opening retained earnings at the date of initial application; however, we did not have any material adjustment as of the date of the adoption. The comparative periods have not been restated.


In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This standard requires all leases that have a term of over 12 months to be recognized on the balance sheet with the liability for lease payments and the corresponding right-of-use asset initially measured at the present value of amounts expected to be paid over the term. Recognition of the costs of these leases on the income statement will be dependent upon their classification as either an operating or a financing lease. Costs of an operating lease will continue to be recognized as a single operating expense on a straight-line basis over the lease term. Costs for a financing lease will be disaggregated and recognized as both an operating expense (for the amortization of the right-of-use asset) and interest expense (for interest on the lease liability). This standard will be effective for our interim and annual periods beginning January 1, 2019, and will be applied on a modified retrospective basis to leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Early adoption is permitted. The Company has evaluated the timing of adoption and the potential impact of this standard on our financial position, but we do not expect it to have a material impact on our financial position or results of operations.


In July 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-11, “Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part 1) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Non-public Entities and Certain Mandatorily Redeemable Non-controlling Interests with a Scope Exception” (“ASU 2017-11”). Part I relates to the accounting for certain financial instruments with down round features in Subtopic 815-40, which is considered in determining whether an equity-linked financial instrument qualifies for a scope exception from derivative accounting. Down round features are features of certain equity-linked instruments (or embedded features) that result in the strike price being reduced based on the pricing of future equity offerings. An entity still is required to determine whether instruments would be classified as equity in determining whether they qualify for that scope exception. If they do qualify, freestanding instruments with down round features are no longer classified as liabilities. ASU 2017-11 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption is permitted, including in an interim period. We adopted Topic 815 as of January 1, 2018.The effect was to no longer recognize certain freestanding instruments with down round features as a liability, through an increase in beginning retained earnings of $807,762.

Subsequent events

The Company has evaluated all events subsequent to December 31, 2018, and through April 1, 2019. There were no subsequent events that need disclosure.