| 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 Vikings 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 (and its subsidiaries) and Ichor Energy Holdings, LLC, its subsidiary Ichor Energy, LLC (Ichor Energy), and Ichor Energys subsidiaries, Ichor Energy (TX), LLC, and Ichor Energy (LA), LLC, which provide 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 oil and gas reserves are used as significant inputs in determining the depletion of oil and gas properties and the impairment of proved oil and gas properties. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved 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 accrued expenses and other current liabilities, accounts payable, derivative liabilities, amount due to director 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 June 30, 2019 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 $ - $ - $ - $ - $ - $ - $ - $ - Financial liabilities Commodity Derivative $ $ 7,121,509 $ - $ (5,271,567 ) $ - $ 7,121,509 $ - $ (5,271,567 ) Assets and liabilities measured at fair value as of December 31, 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 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 ) The Company has entered into certain commodity derivative instruments containing swaps and collars, which management believes 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. 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 Companys 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 Companys 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. 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 also entered into collar agreements related to oil and gas production with established floors and ceilings. Upon settlement, if the current market price of the commodity is below the floor, the Company receives the difference. Conversely, if the current market price of the commodity is above the ceiling at settlement, the Company pays the excess over the ceiling price. 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 derivative assets were $0 and $681,776 as of June 30, 2019 and December 31, 2018, and the derivative liabilities were $7,121,509 and $2,531,718 as of June 30, 2019 and December 31, 2018 respectively. The change in the fair value of the derivative assets and liabilities for the six months ended June 30, 2019 consisted of a decrease of $681,776 associated with existing commodity derivatives and a decrease of $4,589,791 associated with the new commodity derivative related to the acquisition accomplished on December 28, 2018, and a loss recognized in the consolidated statement of operations in the amount of $5,271,567. The table below is a summary of the Companys commodity derivatives as of June 30, 2019: 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 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 June 30, 2019, the Company has cash deposits in excess of FDIC insured limits in the amounts of $3,867,375. Restricted cash in the amount of $4,683,129 as of June 30, 2019 represents the balance of cash held by Ichor Energy, LLC (the Borrower) and/or its subsidiaries, generated through the operations of those subsidiaries. Pursuant to the Term Loan Credit Agreement to which the Borrower and its subsidiaries are parties, following March 31, 2019 the Borrower is required at all times to maintain a minimum cash balance of $2,000,000 (the MLR). Within 30 days of the end of each quarter, commencing with the quarter ended June 30, 2019, the Borrower is required to pay the lenders, as an additional principal payment on the debt, any cash in excess of (i) the MLR and (ii) any funds necessary for the capital expenditures contemplated to be expended in the next six month period by an approved plan of development (APOD Capex Amount). At June 30, 2019, the cash in excess of the MLR does not exceed the APOD Capex Amount. 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 June 30, 2019 and December 31, 2018 respectively. g) 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 Companys oil and gas properties for the three and six months ended June 30, 2019 and 2018 were as follows: Three months ended Six months ended June 30, June 30, Cost Center 2019 2018 2019 2018 Canada $ - $ 10,649 $ - $ 21,387 United States 2,228,191 449,302 4,598,879 928,250 $ 2,228,191 $ 459,951 $ 4,598,879 $ 949,637 h) 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. i) 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. j) Income (loss) per Share Basic net 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 outstanding and adjusted by any effects of warrants and options outstanding during the period, if dilutive. For the three months ended June 30, 2019 there were approximately 1,411 common stock equivalents that were dilutive; these dilutive shares were immaterial and omitted from the calculation of income per share for such period. For the six months ended June 30, 2019 and 2018 there were approximately 92,274,782 and 34,912,910 common stock equivalents respectively, that were anti-dilutive. k) Revenue Recognition 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 Companys 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 Companys revenue by source for the six months ended June 30, 2019 and 2018: Three months ended Six months ended June 30, June 30, 2019 2018 2019 2018 Oil $ 7,194,400 $ 2,248,725 $ 14,926,562 $ 4,272,909 Natural gas and natural gas liquids 1,539,923 69,897 3,154,353 207,660 $ 8,734,323 $ 2,318,622 $ 18,080,915 $ 4,480,569 l) 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, management evaluated whether it is more likely than not that some portion, or all of its deferred tax assets, will be realized. The realization of its deferred tax assets relates directly to the Companys ability to generate taxable income. The valuation allowance is then adjusted accordingly. The Company has estimated net operating losses in excess of $12,000,000 at June 30, 2019. The potential benefit of these net operating losses has not been recognized in these financial statements because the Company cannot be assured it is more likely than not that it will utilize the net operating losses carried forward in future years. In December 2017, tax legislation was enacted limiting the deduction for net operating losses from taxable years beginning after December 31, 2017 to 80% of current year taxable income and eliminating net operating loss carrybacks for losses arising in taxable years ending after December 31, 2017 (though any such tax losses may be carried forward indefinitely). Net operating losses originating in taxable years beginning prior to January 1, 2018 are still subject to former carryover rules. The net operating loss carryforwards generated prior to this date, approximating $11,000,000, will expire between 2019 through 2038. m) 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 Companys 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. The following table represents stock warrant activity as of and for the six months ended June 30, 2019: Number of Shares Weighted Average Exercise Price Weighted Average Remaining Contractual Life Aggregate Intrinsic Value Warrants Outstanding – December 31, 2018 54,821,690 $ 0.26 6.0 years $ - Granted - - - Exercised - - - - Forfeited/expired/cancelled - - - Warrants Outstanding – June 30, 2019 54,821,690 $ 0.26 4.7 years $ - Outstanding Exercisable – June 30, 2019 54,821,690 $ 0.26 4.7 years $ - n) Impairment 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 assets 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 six months ended June 30, 2019 and 2018. o) 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 obligations inception, with an offsetting increase to proved properties. The following table describes the changes in the Companys asset retirement obligations for the six months ended June 30, 2019: Six months ended June 30, 2019 Asset retirement obligation beginning $ 4,413,465 Oil and gas purchases 94,796 Adjustments through disposals and settlements (797,796 ) Accretion expense 158,227 Asset retirement obligation ending $ 3,868,692 p) 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. q) Recent Accounting Pronouncements In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update No. 2016-02 Leases (ASU 2016-02) and subsequently issued supplemental adoption guidance and clarification (collectively, Topic 842). Topic 842 amends a number of aspects of lease accounting, including requiring lessees to recognize right-of-use assets and lease liabilities for operating leases with a lease term greater than one year. Topic 842 supersedes Topic 840 Leases. On January 1, 2019, the Company adopted Topic 842 using the modified retrospective approach. Results for reporting periods beginning after January 1, 2019 are presented under Topic 842, while prior period amounts are not adjusted and continue to be reported in accordance with our historical accounting under Topic 840. We elected the package of practical expedients permitted under the transition guidance within Topic 842, which allowed us to carry forward the historical lease classification, retain the initial direct costs for any leases that existed prior to the adoption of the standard and not reassess whether any contracts entered into prior to the adoption are leases. We also elected to account for lease and non-lease components in our lease agreements as a single lease component in determining lease assets and liabilities. In addition, we elected not to recognize the right-of-use assets and liabilities for leases with lease terms of one year or less. Upon adoption of Topic 842, we recorded $367,365 of right-of-use assets and operating lease liabilities as of January 1, 2019. The adoption did not have a material impact on our Consolidated Statements of Operations or Consolidated Statements of Cash Flows. r) Subsequent events The Company has evaluated all subsequent events from June 30, 2019, through the date of filing this report, and determined there are no additional items to disclose other than those described in Note 9. |
