Summary of Significant Accounting Policies
|12 Months Ended|
Dec. 31, 2018
|Accounting Policies [Abstract]|
|Summary of Significant Accounting Policies||
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of consolidation
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Askarii Resources and Petrolia Canada Corporation. All significant intercompany balances and transactions have been eliminated upon consolidation.
The Company accounts for its investment in companies in which it has significant influence by the equity method. The Company’s proportionate share of earnings is included in earnings and added to or deducted from the cost of the investment.
Foreign currency translation
The functional and reporting currency of the Company is the United States dollar. The functional currencies of the Company’s wholly-owned subsidiaries, Askarii Resources and Petrolia Canada Corporation, are the United States dollar and the Canadian dollar, respectively. Transactions involving foreign currencies are converted into the Company’s functional currency using the exchange rates in effect at the time of the transactions. At the balance sheet date, monetary assets and liabilities that are denominated in currencies other than the Company’s functional currency are translated using exchange rates at that date. Exchange gains and losses are included in net earnings. On consolidation, Petrolia Canada Corporation’s income statement amounts are translated at average exchange rates for the year, while the assets and liabilities are translated at year-end exchange rates. Translation adjustments are accumulated as a separate component of stockholders’ equity in other comprehensive income.
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates made in preparing these financial statements include depreciation of furniture, equipment and software, asset retirement obligations (“AROs”) (Note 10), income taxes (Note 14) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 16).
Cash and cash equivalents
The Company considers all highly liquid instruments purchased with an original maturity date of three months or less to be cash equivalents. At December 31, 2018, the Company did not hold any cash equivalents.
Receivables and allowance for doubtful accounts
Oil revenues receivable do not bear any interest. These receivables are primarily comprised of joint interest billings. Management regularly reviews collectability and establishes or adjusts an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.
Oil and gas properties
The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. 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 capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to operations.
The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves.
The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful.
All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization.
Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the “cost ceiling”) equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to operations. For purposes of the ceiling test calculation, current prices are defined as the un-weighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period. Prices are adjusted for basis or location differentials. Unless sales contracts specify otherwise, prices are held constant for the productive life of each well. Similarly, current costs are assumed to remain constant over the entire calculation period.
Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
Furniture, equipment and software
Furniture, equipment, and software are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. Management performs ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred. Management periodically reviews long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. The Company recognizes an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value.
Derivative financial instruments
The Company’s derivative financial instruments consist of warrants with an exercise price denominated in a currency other than the Company’s functional currency. These derivative financial instruments are measured at their fair value at the end of each reporting period. Changes in fair value are recorded in net income.
Asset retirement obligations
The Company records a liability for AROs associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value.
Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.
Debt issuance costs
Costs incurred in connection with the issuance of long-term debt are presented as a direct deduction from the carrying value of the related debt and amortized over the term of the related debt.
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This update creates a five-step model that requires entities to exercise judgment when considering the terms of the contract(s) which includes (i) identifying the contract(s) with the customer, (ii) identifying the separate performance obligations in the contract, (iii) determining the transaction price, (iv) allocating the transaction price to the separate performance obligations, and (v) recognizing revenue as each performance obligation is satisfied. The Company adopted this standard on a modified retroactive basis on January 1, 2018. No financial statement impact occurred upon adoption.
Revenue from contracts with customers
The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration the Company expects to receive in exchange for those products.
Performance obligations and significant judgments
The Company sells oil and natural gas products in the United States through a single reportable segment. The Company enters into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product.
The oil and natural gas is typically sold in an unprocessed state to processors and other third parties for processing and sale to customers. The Company recognizes revenue at a point in time when control of the oil or natural gas passes to the customer or processor, as applicable, discussed below. For oil sales, control is typically transferred to the customer upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with processors, control transfers upon delivery at the wellhead or the inlet of the processing entity’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. In the cases where the Company sells to a processor, management has determined that the Company is the principal in the arrangement and the processors are customers. The Company recognizes the revenue in these contracts based on the net proceeds received from the processor.
Transfer of control drives the presentation of transportation and gathering costs within the accompanying consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recorded as a reduction to the related revenue.
A portion of our product sales are short-term in nature. For those contracts, the Company uses the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.
For our product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has no unsatisfied performance obligations at the end of each reporting period.
Management does not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained.
The Company accounts for stock-based compensation to employees in accordance with FASB ASC 718. Stock-based compensation to employees is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite employee service period. The Company accounts for stock-based compensation to other than employees in accordance with FASB ASC 505-50. Equity instruments issued to other than employees are valued at the earlier of a commitment date or upon completion of the services, based on the fair value of the equity instruments, and is recognized as expense over the service period. The Company estimates the fair value of stock-based payments using the Black-Sholes Option Pricing Model for common stock options and warrants and the closing price of the Company’s common stock for common share issuances. The Company may grant stock to employees and non-employees in exchange for goods, services or for settlement of liabilities. Shares granted to employees in exchange for goods, services or settlement of liabilities are measured based on the fair value of the shares issued. Shares granted to non-employees in exchange for goods or services are measured based on the fair value of the consideration received or the fair value of the shares issued, whichever is more reliably measurable.
Income taxes are accounted for pursuant to ASC 740, Income Taxes, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. The Company provides for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.
Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in the income tax provision. There are currently no unrecognized tax benefits that if recognized would affect the tax rate. There was no interest or penalties recognized for the twelve months ended December 31, 2018 and 2017.
The Company is required to file federal income tax returns in the United States and Canada, and in various state and local jurisdictions. The Company’s tax returns filed since the 2016 tax year are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.
Earnings (loss) per share
Basic earnings (loss) per share has been calculated based on the weighted-average number of common shares outstanding. The treasury stock method is used to compute the dilutive effect of the Company’s share-based compensation awards. Under this method, the incremental number of shares used in computing diluted earnings per share (“EPS”) is the difference between the number of shares assumed issued and purchased using assumed proceeds. Diluted EPS amounts would include the effect of outstanding stock options, warrants, and other convertible securities if including such potential shares of common stock is dilutive. Basic and diluted earnings per share are the same in all periods presented as all outstanding instruments are anti-dilutive.
Concentration of credit risk
The Company is subject to credit risk resulting from the concentration of its oil receivables with significant purchasers. Two purchasers accounted for all of the Company’s oil sales revenues for 2018 and 2017. The Company does not require collateral. While the Company believes its recorded receivables will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of a purchaser would materially impact its operating results as oil is a fungible product with a well-established market and numerous purchasers.
At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.
Fair value measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (i.e., the “exit price”) in an orderly transaction between market participants at the measurement date. The hierarchy is broken down into three levels based on the observability of inputs as follows:
The carrying value of cash, accounts receivable, other current assets, accounts payable, accounts payable – related parties, accrued liabilities and accrued liabilities – related parties, as reflected in the consolidated balance sheets, approximate fair value, due to the short-term maturity of these instruments. The carrying value of notes payable approximates their fair value due to immaterial changes in market interest rates and the Company’s credit risk since issuance of the instruments or due to their short-term nature. Derivative liabilities are remeasured at fair value every reporting period. The fair values are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. Therefore, derivative liabilities are considered level 2 financial instruments.
The Audit Committee approves all material related party transactions. The Audit Committee is provided with the details of each new, existing or proposed related party transaction, including the terms of the transaction, the business purpose of the transaction, and the benefits to the Company and the relevant related party. In determining whether to approve a related party transaction, the following factors are considered: (1) if the terms are fair to the Company, (2) if there are business reasons to enter into the transaction, (3) if the transaction would impair independence of an outside Director, or (4) if the transaction would present an improper conflict of interest for any Director or executive officer. Any member of the Audit Committee who has an interest in the transaction will abstain from voting on the approval of the related party transaction.
In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The ASU provides an updated model for determining if acquired assets and liabilities constitute a business. In a business combination, the acquired assets and liabilities are recognized at fair value and goodwill could be recognized. In an asset acquisition, the assets are allocated value based on relative fair value and no goodwill is recognized. The ASU narrows the definition of a business. The Company adopted this standard on January 1, 2018. ASU 2017-01 did not have a material impact on our financial statements on adoption.
Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net loss, working capital or equity previously reported.
Recent accounting pronouncements
The Company has evaluated all the recent accounting pronouncements through the filing date and believes that none of them will have a material effect on the Company other than those discussed below.
In February 2016, the FASB issued ASU 2016-02, “Leases”, which requires lessees to recognize all rights and obligations created by those leases, including operating leases, with a term greater than 12 months on the balance sheet. The accounting for lessors will remain largely unchanged from the existing accounting standards. The standard is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years.
Under ASU 2016-02, each lease agreement will be evaluated to identify the lease components and non-lease components at lease inception. The total consideration in the lease agreement will be allocated to the lease and non-lease components based on their relative standalone selling prices.
In July 2018, the FASB issued ASU 2018-11, “Leases – Targeted Improvements” that allows lessors to elect, as a practical expedient, to not separate lease and non-lease components and allows these components to be accounted for as a single lease component if both (1) the timing and pattern of transfer to the lessee of the lease component and the related non-lease component are the same and (2) the lease component, if accounted for separately, would be classified as an operating lease. In addition, a company is permitted to use its effective date as the date of initial application. Therefore, a company electing this option will not restate comparative period financial information, will not make the new required lease disclosures in comparative periods beginning before the effective date and will recognize its cumulative effect transition adjustment as of the effective date. Under the practical expedient mentioned above, it is expected that revenue will be presented under a single lease component presentation. The Company will elect this expedient upon adoption.
The Company intends to adopt ASU 2016-02 on January 1, 2019 using the modified retrospective method, whereby a cumulative effect adjustment will be made as of that day with no retrospective effect. The Company also intends to elect to apply the package of practical expedients such that for any expired or existing leases it will not reassess lease classification, initial direct costs or whether any expired or existing contracts are or contain leases.
The entire disclosure for all significant accounting policies of the reporting entity.
Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef