| Note 2 - Summary of Significant Accounting Policies | a) Basis of Presentation The accompanying unaudited consolidated financial
statements of the Company have been prepared in accordance with generally accepted accounting principles in the United States of
America (“GAAP”) and the interim reporting rules of the Securities and Exchange Commission (“SEC”) and
should be read in conjunction with the audited financial statements and notes thereto contained in Viking’s latest Annual
Report filed with the SEC on Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments
(unless otherwise indicated), necessary for a fair presentation of the financial position and the results of operations for the
interim periods presented have been reflected herein. The results of operations for interim periods are not necessarily indicative
of the results to be expected for the full year. 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 based in Houston, Texas 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 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, 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 significantly
from the estimates and assumptions utilized. d) Financial Instruments 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. Liabilities measured at fair value as of September
30, 2018 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 $ - $ - $ - $ -
Commodity Derivative - - - -
$ - $ - $ - $ -
Financial liabilities
Derivative liabilities $ - $ - $ - $ -
Commodity Derivative 1,575,128 - (1,330,102 )
$ - $ 1,575,128 $ - $ (1,330,102 )
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’s long-term investment consisted
of 1,437,500 common shares of Tanager Energy Inc., as of December 31, 2016, which is traded on the TSX Venture Exchange (Toronto
Stock Exchange). 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 three months ended March 31, 2017. The Company had commodity financial derivatives
in place at September 30, 2018. 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, the instruments themselves are traded with unrelated counterparties and are not openly traded on an exchange. The Company uses the Black-Scholes model to
value its derivative liabilities. This model considers inputs such as contract terms, including maturity and market parameters,
including assumptions associated with interest rates, volatility and credit worthiness. The derivative assets and liabilities of
the Company were $1,575,128 as of September 30, 2018 and $1,052,788 as of December 31, 2017. The change in the fair value of the
derivative liabilities for the nine months ended September 30, 2018, consisted of an increase of $1,330,102 associated with commodity
derivatives. The decrease in the derivative liabilities associated with warrants and the conversion features of convertible debt
in the amount of $807,762 are the result of the Company adopting ASU 2017-11, Derivatives and Hedging (Topic 815) I. Accounting
for Certain Instruments with Down Round Features . The carrying amounts reported in the consolidated
balance sheets for other receivable – related party, accrued expenses and other current liabilities, accounts payable, derivative
liabilities, 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. 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 September 30, 2018 and December
31, 2017, the Company has cash deposits in excess of FDIC insured limits in the amounts of $4,611,601 and $5,372,818, respectively. Restricted cash in the amount of $3,500,000
as of September 30, 2018 represents cash held in escrow as a deposit on a pending acquisition of oil and gas properties. Restricted
cash in the amount of $5,199,103 as of December 31, 2017 represents cash held in escrow related to the Petrodome acquisition, and
was restricted for drilling and exploration at the time. f) Accounts Receivable Accounts receivable consist of oil and gas
receivables. The Company has classified these as short-term assets in the balance sheet because the Company expects payment or
recovery within the next 12 months. The Company evaluates these accounts receivable for collectability and, when necessary, records
allowances for expected unrecoverable amounts. The Company deems all receivables to be collectable at September 30, 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 September 30, 2018 and December 31, 2017, the balances of the prepaid equity-based compensation were comprised of the following:
September 30, 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 continuing 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 three and nine months ended September
30, 2018 and 2017, were as follows:
Oil and Gas Properties by Geographical Cost Center
Three months ended September 30,
Nine months ended, September 30,
Cost Center 2018 2017 2018 2017
Canada $ - $ 21,073 $ 21,387 $ 38,301
United States 412,669 38,638 1,340,919 108,301
$ 412,669 $ 59,711 $ 1,362,306 $ 146,602 i) Limitation on Capitalized Costs Under the full-cost method of accounting, the
Company is required, at the end of each reporting date, to perform a test to determine the limit on the book value of oil and natural
gas properties (the “Ceiling” test). If the capitalized costs of its 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, 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 oil and natural gas properties. 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) Loss Per Share Basic net loss per share is computed by dividing
the net loss by the weighted-average number of common shares outstanding during the period. Diluted net loss per share is computed
by dividing the net 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 September 30, 2018 and 2017, there were approximately
40,807,159 and 10,145,834 common stock equivalents respectively, that were anti-dilutive. 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 three and nine-month periods ended September 30, 2018 and 2017:
Three Months Ended September 30, Nine Months Ended September 30,
2018 2017 2018 2017
Oil $ 1,872,636 212,273 $ 6,145,546 $ 570,522
Natural gas and Natural gas liquids 23,296 9,056 230,955 18,100
$ 1,895,932 $ 221,329 $ 6,376,501 $ 588,622
m) Other Comprehensive Income ASC Topic 220, “Comprehensive Income,”
establishes standards for the reporting and presentation of comprehensive income and its components in the consolidated financial
statements. For the nine months ended September 30, 2018 and 2017, comprehensive income (loss) was $0 and $1,446 respectively and
consisted primarily of unrealized gains and (losses) on available for sale securities. n) 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 would be fully realized. Accordingly, the Company recorded a deferred
tax liability of $910,827. During the nine months ended September 30, 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.
o) 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 nine months ended September 30,
2018, the Company granted 14,512,159 warrants to purchase common stock, of which all but 2,500,000 vested immediately. 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 296% to 297 %
Dividend Yield 0 % At September 30, 2018, there was approximately
$499,500 of 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 nine months ended September 30, 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 14,512,159 0.27 4.8 years -
Exercised (1,145,626 ) - - -
Forfeited/expired/cancelled - - -
Warrants Outstanding – September 30, 2018 40,807,159 $ 0.27 6.7 years $ -
Outstanding Exercisable – December 31, 2017 27,440,626 $ 0.27 8.2 years $ -
Outstanding Exercisable – September 30, 2018 40,807,159 $ 0.27 6.7 years $ - p) 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 nine months ended September 30, 2018 and 2017.
q) 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 previously had oil and gas operations in Alberta, Canada in which the Canadian Dollar (“CAD” or “CS”
herein) was the primary economic environment. For financial reporting purposes, the operational
results of the Company’s oil and gas operations in Canada were prepared using the CAD, and 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 loss in stockholders’ deficit when realized.
There have been no settlement transactions that resulted in the recognition of a foreign currency exchange gain or loss during
the nine months ended September 30, 2018 and 2017. r) 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 its convertible notes. The conversion feature did not meet the definition of “indexed to a company’s own stock”
due to the down round protection feature. Therefore, the conversion feature requires bifurcation and liability classification.
Additionally, the default put requires bifurcation because it is indexed to risks that are not associated with credit or interest
risk. As a result, the compound embedded derivative comprises of (i) the embedded conversion feature and (i) the default put.
Rather than bifurcating and recording the compound embedded derivative as a derivative liability, the Company elected to initially
and subsequently measure the convertible note in its entirety 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. 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 nine months ended September 30, 2018, and the year ended December 31,
2017:
Nine months ended September 30, 2018
Year ended December 31, 2017
Asset retirement obligation – beginning $ 3,096,263 $ 833,017
Oil and gas purchases 231,053 2,205,171
Adjustments through disposals and settlements (669,840 ) -
Accretion expense 137,858 58,075
Asset retirement obligation – ending $ 2,795,334 $ 3,096,263 t) 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. u) Recent Accounting Pronouncements As of September 30, 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. We 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 must 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. We are currently evaluating 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 |
