SIGNIFICANT ACCOUNTING POLICIES
|9 Months Ended|
Jun. 30, 2020
|Accounting Policies [Abstract]|
|SIGNIFICANT ACCOUNTING POLICIES||
NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES
The condensed financial statements included herein are unaudited. However, these condensed financial statements include all adjustments (consisting of normal recurring adjustments), which, in the opinion of management are necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year. The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Company’s condensed financial statements and accompanying notes. Actual results could differ materially from those estimates.
Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP“) have been omitted pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC“). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended September 30, 2019, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019, and filed with the Securities and Exchange Commission on December 30, 2019.
GulfSlope considers highly liquid investments with original maturities to the Company of three months or less to be cash equivalents. There were no cash equivalents at June 30, 2020 and September 30, 2019.
The Company has incurred accumulated losses as of June 30, 2020 of $59.1 million, has negative working capital of $18.4 million and for the nine months ended June 30, 2020 generated losses of $3.5 million. Further losses are anticipated in developing our business. As a result, there exists substantial doubt about our ability to continue as a going concern. As of June 30, 2020, we had $1.06 million of unrestricted cash on hand. $0.8 million of this amount is for the payment of joint payables from drilling operations. The Company estimates that it will need to raise a minimum of $10.0 million to meet its obligations and planned expenditures. The $10.0 million is comprised primarily of capital project expenditures as well as general and administrative expenses. It does not include any amounts due under outstanding debt obligations, which amounted to $14.9 million of current principal and accrued interest as of June 30, 2020. The Company plans to finance operations and planned expenditures through the issuance of equity securities, debt financings and farm-out agreements, mergers or other transactions to include the cash settlement of the Company’s insurance claim. The Company also plans to extend the agreements associated with all loans, the accrued interest payable on these loans, as well as the Company’s accrued liabilities. There are no assurances that financing will be available with acceptable terms, if at all or that obligations can be extended. If the Company is not successful in obtaining financing or extending obligations, operations would need to be curtailed or ceased, or the Company would need to sell assets or consider alternative plans up to and including restructuring. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
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, the receivable and the underlying asset are assessed for recovery. As of June 30, 2020 and September 30, 2019, no allowance was recorded. Accounts receivable from oil and gas joint operations and joint ventures is $0.3 million and $8.5 million at June 30, 2020 and September 30, 2019, respectively. During the nine months ended June 30, 2020, approximately $3.6 million of accounts receivable from a joint interest partner was exchanged for an 5% additional working interest in the Tau and Canoe wells and accordingly $3.6 million was reclassified to oil and natural gas properties.
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 that considers, 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 regarding the commerciality of the well. If sufficient 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, since we currently have no proved reserves.
Due to a combination of the COVID-19 pandemic and related pressures on the global supply-demand balance for crude oil and related products, commodity prices have significantly declined in recent months, and oil and gas operators have reduced exploration budgets and activity. The Company has evaluated the effect of these factors on its business and the Company has determined that these factors will most likely cause a delay in the Company’s 2020 drilling program. The Company continues to monitor the economic environment and evaluate the impact on the business.
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 cost required and as such, the asset retirement obligation was completely extinguished.
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.
Basic and Dilutive Earnings Per Share
Basic income (loss) per share (“EPS“) is computed by dividing net loss (the numerator) by the weighted average number of common shares outstanding for the period (denominator). 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, and convertible notes payable. The number of potential common shares outstanding relating to stock options and warrants, is computed using the treasury stock method. The number of potential common shares related to convertible notes payable is determined using the if-converted method.
As the Company has incurred losses for the nine months ended June 30, 2020 and 2019, the potentially dilutive shares are anti-dilutive and are thus not added into the loss per share calculations. As of June 30, 2020 and 2019, there were 586,722,166 and 357,582,559 potentially dilutive shares, respectively.
Recent Accounting Pronouncements
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 11.
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 three months ended December 31, 2019.
The Company has evaluated all other recent accounting pronouncements and believes that none of them will have a significant effect on the Company’s financial statements.
The entire disclosure for all significant accounting policies of the reporting entity.
Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef