| Note 2 - Summary of Significant Accounting Policies | a) 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. b) 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. c) 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. d) 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:
Description
Quoted Prices in Active Markets for Identical Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Total Gains (Losses)
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:
Description
Quoted Prices in Active Markets for Identical
Assets (Level 1)
Significant Other Observable Inputs (Level 2)
Significant Unobservable Inputs (Level 3)
Total Gains (Losses)
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:
Gross Amounts Offsets on the Consolidated Balance Sheet
Net Amount
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 e) 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. f) 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. g) 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, 2018
December 31, 2017
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 h) 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 i) 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. j) 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. k) 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. l) 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 m) 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. n) 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 Shares
Weighted Average Exercise Price
Weighted Average Remaining Contractual Life
Aggregate Intrinsic Value
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 $ - o) 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. p) 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. p) 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). q) 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, 2018
Year ended December 31, 2017
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 r) 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. s) Recent 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 fin |
