ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
|12 Months Ended|
Sep. 30, 2020
|Accounting Policies [Abstract]|
|ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES||
NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GulfSlope Energy, Inc. (the “Company or “GulfSlope) is an independent oil and natural gas exploration company whose interests are concentrated in the United States Gulf of Mexico federal waters offshore Louisiana. The Company has leased three federal Outer Continental Shelf blocks (referred to as “prospect, “portfolio or “leases) and licensed three-dimensional (3-D) seismic data in its area of concentration.
(b) Basis of Presentation
The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP) and the instructions to Form 10-K and Regulation S-X published by the US Securities and Exchange Commission (the “SEC). The accompanying financial statements include the accounts of the Company.
(c) Going Concern
The Company’s financial statements have been presented on the basis that it is a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The Company has incurred net losses through September 30, 2020 of $58.0 million, has a lack of cash on-hand, and a working capital deficit of approximately $10.3 million. These factors raise substantial doubt as to the Company’s ability to continue as a going concern. Management intends to raise additional operating funds through equity and/or debt financings, and strategic transactions to include farm-outs, asset sales or mergers. Management also plans to extend the agreements associated with loans from related parties, the accrued interest payable on these loans, as well as the Company’s accrued liabilities. However, there can be no assurance that additional financing will be available, or if available, will be on terms acceptable to the Company. If adequate working capital is not available, the Company may be required to curtail or cease operations, or the Company would need to sell assets or consider alternative plans up to and including restructuring.
The Company considers all short-term highly liquid investments with an original maturity at the date of purchase of three months or less to be cash equivalents. There were no cash equivalents at September 30, 2020 and 2019, respectively.
(e) Accounts Receivable
The Company records an accounts receivable for operations expense reimbursements due from joint interest partners. The Company estimates allowances for doubtful accounts based on the aged receivable balances and historical losses. If the Company determines any account to be uncollectible based on significant delinquency or other factors, we assess the receivable and the underlying asset for recovery. As of September 30, 2020 and 2019, no allowance was recorded. Accounts receivable were approximately $0.4 million at September 30, 2020. Accounts receivable from oil and gas joint operations were approximately $12.1 million at September 30, 2019, including $3.7 million classified as other non-current assets. This amount was an unpaid joint interest billing receivable and the working interest was re-conveyed to GulfSlope in November of 2019 in exchange for full settlement of the amount due.
(f) Full Cost Method
The Company uses the full cost method of accounting for its oil and gas exploration and development activities. Under the full cost method of accounting, all costs associated with successful and unsuccessful exploration and development activities are capitalized on a country-by-country basis into a single cost center (“full cost pool). Such costs include property acquisition costs, geological and geophysical (“G&G) costs, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells. Overhead costs, which includes employee compensation and benefits including stock-based compensation, incurred that are directly related to acquisition, exploration and development activities are capitalized. Interest expense is capitalized related to unevaluated properties and wells in process during the period in which the Company is incurring costs and expending resources to get the properties ready for their intended purpose. For significant investments in unproved properties and major development projects that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress, interest costs are capitalized. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.
Proved properties are amortized on a country-by-country basis using the units of production method (“UOP), whereby capitalized costs are amortized over total proved reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A), estimated future development costs (future costs to access and develop proved reserves), and asset retirement costs, less related salvage value.
The costs of unproved properties and related capitalized costs (such as G&G costs) are withheld from the amortization calculation until such time as they are either developed or abandoned. Unproved properties and properties under development are reviewed for impairment at least quarterly and are determined through an evaluation by management and third party consultants considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. In countries where a reserve base has not yet been established, impairments are charged to earnings.
Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depreciation, depletion and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
The Company capitalizes exploratory well costs into oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. The well costs are charged to expense if the exploratory well is determined to be impaired. The Company is currently evaluating one well for proved reserves and remain pending the outcome of exploration activities involving the drilling of the Tau No. 2 well (twin well). Accordingly, this costs is included as suspended well costs at September 30, 2020 and it is expected that a final analysis will be completed in the next twelve months at which time the costs will be transferred to the full cost pool upon final evaluation.
As of September 30, 2020, the Company’s oil and gas properties consisted of unproved properties, wells in process and no proved reserves.
(g) Asset Retirement Obligations
The Company’s asset retirement obligations will represent the present value of the estimated future costs associated with plugging and abandoning oil and natural gas wells, removing production equipment and facilities and restoring the seabed in accordance with the terms of oil and gas leases and applicable state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and natural gas wells, removing production equipment and facilities and restoring the sea bed as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows will be discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates will consider historical experience, third party estimates, the requirements of oil and natural gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations will be recognized when the wells drilled reach total depth or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations will be accreted each period through depreciation, depletion and amortization to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations will be included in net cash provided by operating activities from continuing operations in the statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company will assess all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Future revisions could occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and natural gas wells. The Company drilled two well bores in 2018 and 2019 and these wellbores were both plugged with no further future cost required and as such, the asset retirement obligation was completely extinguished.
(h) Property and Equipment
Property and equipment are carried at cost and include expenditures for new equipment and those expenditures that substantially increase the productive lives of existing equipment and leasehold improvements. Maintenance and repair costs are expensed as incurred. Property and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives. Fully depreciated property and equipment still in use are not eliminated from the accounts.
The Company assesses the carrying value of its property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows, expected to be generated from such assets, to their net book value. If net book value exceeds estimated cash flows, the asset is written down to its fair value, determined by the estimated discounted cash flows from such asset. When an asset is retired or sold, its cost and related accumulated depreciation and amortization are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss in our statements of operations in the period in which they occur.
(i) Income Taxes
Deferred tax assets and liabilities are recognized for the temporary differences between the financial reporting basis and tax basis of the Company’s assets and liabilities at enacted tax rates expected to be in effect when such amounts are realized or settled. A valuation allowance is provided if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company’s policy is to recognize potential interest and penalties as a component of income tax expense when incurred.
(j) Stock-Based Compensation
The Company records expenses associated with the fair value of stock-based compensation. For fully vested and restricted stock grants, the Company calculates the stock based compensation expense based upon estimated fair value on the date of grant. For stock warrants and options, the Company uses the Black-Scholes option valuation model to calculate stock based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.
(k) Stock Issuance
The Company records stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.
(l) Earnings per Share
Basic earnings per share (“EPS) is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. Diluted EPS is computed by dividing net income (loss) by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants, convertible notes and restricted stock. The number of potential common shares outstanding relating to stock options, warrants, and restricted stock is computed using the treasury stock or if-converted method.
As the Company has incurred losses for the years ended September 30, 2020 and 2019, the potentially dilutive shares are anti-dilutive and thus not added into the EPS calculations. As of September 30, 2020 and 2019, there were 259,392,057 and 354,818,379 potentially dilutive shares, respectively.
(m) Derivative Financial Instruments
The accounting treatment of derivative financial instruments requires that the Company record certain embedded conversion options and warrants as liabilities at their fair value as of the inception date of the agreement and at fair value as of each subsequent balance sheet date with any change in fair value recorded as income or expense. As a result of entering into certain note agreements, for which such instruments contained a variable conversion feature with no floor, the Company has adopted a sequencing policy in accordance with ASC 815-40-35-12 whereby all future instruments may be classified as a derivative liability with the exception of instruments related to share-based compensation issued to employees or directors, as long as the certain variable convertible instruments exist. See Note 7 – Convertible Notes Payable.
(n) Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the 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.
(o) Impact of New Accounting Standards
In February 2016, the FASB issued ASU No. 2016-02, “Leases, and in March 2019, the FASB issued ASU No. 2019-01, “Leases: Codification Improvements, which updated the accounting guidance related to leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. They also clarify implementation issues. These updates are effective for public companies for annual periods beginning after December 15, 2018, including interim periods therein. Accordingly, the standard was adopted by the Company on October 1, 2019. The standard was applied utilizing a modified retrospective approach and is reflected in these financial statements. See Note 13.
In June 2018, the FASB issued ASU 2018-07, Compensation-Stock Compensation (Topic 718), Improvements to Nonemployee Share-based Payments (“ASU 2018-07). This ASU expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. The amendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company adopted this new standard effective October 1, 2019 with no material impact to stock compensation issued to non-employees during the year ended September 30, 2020.
The Company has evaluated all other recent accounting pronouncements and believes either they are not applicable or that none of them will have a significant effect on the Company’s financial statements.
The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.
Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef