| ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE
1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (a)
Organization 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 one (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)
Cash 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, 2022 and 2021, respectively. (d)
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, 2022, and 2021, no allowance was recorded. Accounts receivable were approximately $ 13,000 (e)
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. As
of September 30, 2022, the Company’s oil and gas properties consisted of unproved properties, capitalized costs and
no proved reserves. (f)
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. (g)
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. (h)
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. (i)
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. (j)
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. (k)
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, 2022 and 2021, the potentially dilutive shares are anti-dilutive
and thus not added into the EPS calculations. As of September 30, 2022 and 2021, there were 289,635,920 297,823,015 (l)
Derivative Financial Instruments The
accounting treatment of derivative financial instruments requires that the Company the
Company (m)
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. (n)
Recently Adopted Accounting Pronouncements In
May 2021, Financial Accounting Standards Board (“FASB”) issued ASU 2021-04, Earnings Per Share (Topic
260), Debt-Modifications and Extinguishments (Subtopic 470-50), Compensation-Stock Compensation (Topic 718), and Derivatives and
Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications
or Exchanges of Freestanding Equity-Classified Written Call Options. ASU 2021-04 provides clarification and reduces diversity
in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such
as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or
exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately
before modification or exchange. ASU 2021-04 introduces a recognition model that comprises four categories of transactions and
the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications
unrelated to equity issuance and debt origination or modification). ASU 2021-04 is effective for all entities for fiscal years
beginning after December 15, 2021, including interim periods within those fiscal years. An entity should apply the guidance provided
in ASU 2021-04 prospectively to modifications or exchanges occurring on or after the effective date. Early adoption is permitted
for all entities, including adoption in an interim period. If an entity elects to early adopt ASU 2021-04 in an interim period,
the guidance should be applied as of the beginning of the fiscal year that includes that interim period. The Company has elected
to early adopt this standard and in accordance with this standard was accounted for prospectively as of the beginning of the year.
The early adoption of this standard impacted the accounting for the modification of investor warrants discussed in Note 7 and
resulted in the recording of a loss on debt extinguishment of approximately $85,000. Historically the cost associated with the
warrant modification was capitalized to deferred loan cost and amortized over the debt extension period. (n)
Recent Accounting Pronouncements Not Yet Adopted In
August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s
Own Equity (ASU 2020-06), which simplifies the accounting for certain financial instruments with characteristics of liabilities
and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, ASU 2020-06
requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per
share (EPS), which is consistent with the Company’s accounting treatment under the current standard. ASU 2020-06
is effective for fiscal years beginning after December 15, 2021, with early adoption permitted for fiscal years beginning after
December 15, 2020. ASU No. 2020-06 can be adopted on either a fully retrospective or modified retrospective basis. The adoption
of ASU 2020-06 is not expected to have a material impact on the Company’s financial statements or disclosures. 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. |
