The accompanying notes are an integral part to these condensed financial statements.

GulfSlope Energy, Inc.

Notes to Condensed Financial Statements

December 31, 2017 June 30, 2020

(Unaudited)

NOTE 1 – ORGANIZATION AND NATURE OF BUSINESS

GulfSlope Energy, Inc. (the “Company,” “GulfSlope,” “our” and words of similar import), a Delaware corporation,“Company“ or “GulfSlope“) is an independent crude oil and natural gas exploration and production company whose interests are concentrated in the United States Gulf of Mexico (“GOM”) federal waters offshore Louisiana. The Company currently has under lease twelvefour federal Outer Continental Shelf blocks (referred to as “prospect,” “portfolio”“ “portfolio“ or “leases” in this Report).

Since March 2013, we have been singularly focused on identifying high-potential oil“leases“) and gas prospects located on the shelf in the U.S. GOM. We have licensed 3-Dthree-dimensional (3-D) seismic data covering approximately 2.2 million acres and have evaluated this data using advanced interpretation technologies. As a resultacross its area of these analyses, we have identified and acquired leases on multiple prospects that we believe may contain economically recoverable hydrocarbon deposits, and we plan to continue to conduct more refined analyses of our prospects as well as target additional lease and property acquisitions. We have given preference to areas with water depths of 450 feet or less where production infrastructure already exists, which will allow for any discoveries to be developed rapidly and cost effectively with the goal to reduce economic risk while increasing returns. We have nine prospects currently under lease that we deem technically complete and ready to drill. Recent actions of the Bureau of Ocean Energy Management (“BOEM”) have reduced the royalty rate for leases acquired in future lease sales in water depths of less than 200 meters (approximately 656 feet) from 18.75% to 12.5%, which further enhances the economics for the drilling of any leases acquired after August 2017 in these water depths. We currently hold one lease to which this reduced rate applies. We expect that drilling activities on two of our prospects will commence in mid-2018.concentration.

As of December 31, 2017, we have no production or proved reserves.

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”GAAP“) have been omitted in this Form 10-Q pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”SEC“). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended September 30, 2017,2019, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 20172019, and filed with the Securities and Exchange Commission on December 29, 2017.30, 2019.

Cash

GulfSlope considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. CashThere were no cash equivalents consist primarily of interest-bearing bank accountsat June 30, 2020 and money market funds.September 30, 2019.

Liquidity/Going Concern

The Company has incurred accumulated losses as of December 31, 2017June 30, 2020 of $39.7$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 December 31, 2017,June 30, 2020, we had $0.1$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$10.0 million to meet its obligations and planned expenditures. The $10.0 million is comprised primarily of capital project expenditures through February 2019.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 its operations and planned expenditures through the issuance of equity securities, debt financings and debt offerings. Our policy has beenfarm-out agreements, mergers or other transactions to periodically raise funds throughinclude the salecash settlement of equitythe Company’s insurance claim. The Company also plans to extend the agreements associated with all loans, the accrued interest payable on a limited basis, to avoid undue dilution while atthese loans, as well as the early stages of execution of our business plan. Short term needs have been historically funded through loans from executive management and other related parties.Company’s accrued liabilities. There are no assurances that financing will be available with acceptable terms, if at all.all or that obligations can be extended. If the Company is not successful in obtaining adequate 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 those associated with being a public reporting company.restructuring. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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, 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 as defined by the Securities and Exchange Commission (“SEC”).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”pool“). Such costs include property acquisition costs, geological and geophysical (“G&G”&G“) costs, carrying charges on non-producing properties, costs of drilling both productive and non-productive wellswells. Overhead costs, which includes employee compensation and overhead chargesbenefits including stock-based compensation, incurred that are directly related to acquisition, exploration and development activities.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). The UOP calculation multiplies the percentage of estimated(“UOP“), whereby capitalized costs are amortized over total proved reserves produced each quarter by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A)(“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 considering,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 limits such pooled costs tois defined as the aggregatesum of the present value of(a) estimated future net revenues, attributable to proved crude oil and natural gas reserves discounted at 10%, plus 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 less any associated tax effects.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.

As of December 31, 2017, the Company’sThe Company capitalizes exploratory well costs into oil and gas properties consisteduntil a determination is made regarding the commerciality of the well. If sufficient proved reserves are found, the capitalized exploration and acquisitionexploratory well costs for unproved properties andare 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”EPS“) is computed by dividing net income (loss)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 restricted stock.convertible notes payable. The number of potential common shares outstanding relating to stock options warrants, and restricted stockwarrants, 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 threenine months ended December 31, 2017June 30, 2020 and 2016,2019, the potentially dilutive shares are anti-dilutive and are thus not added into the loss per share calculations. As of December 31, 2017June 30, 2020 and 2016,2019, there were 175,050,492586,722,166 and 118,268,823357,582,559 potentially dilutive shares, respectively.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is amended by ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, ASU 2016-12, ASU 2016-20, ASU 2017-10, ASU 2017-13 and ASU 2017-14, which FASB issued inAugust 2015, March 2016, April 2016, May 2016, May 2016, December 2016, May 2017, September 2017 and November 2017, respectively (collectively, the amended ASU 2014-09). The amended ASU 2014-09 provides a single comprehensive model for the recognition of revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. It requires an entity to recognize revenue when the entity transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amended ASU 2014-09 creates a five-step model that requires entities to exercise judgment when considering the terms of contract(s), which includes (1) identifying the contract(s) with the customer, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations, and (5) recognizing revenue as each performance obligation is satisfied. The amended ASU 2014-09 requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. The effective date for the amended ASU 2014-09 for the Company is fiscal year 2019, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal year 2018, including interim reporting periods within that reporting period. The Company is evaluating the effect that amended ASU No. 2014-09 will have on its financial statements and related disclosures.

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The new“Leases,“ and in March 2019, the FASB issued ASU No. 2019-01, “Leases: Codification Improvements“, which updated the accounting guidance establishesrelated to leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the principles to report transparentbalance sheet and economically neutraldisclosing 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 assetsstandard was adopted by the Company on October 1, 2019. The standard was applied utilizing a modified retrospective approach and liabilities that ariseis 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 leases.nonemployees. The new guidance isamendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within thosethat fiscal years, and early application is permitted for all organizations.year. The Company has not yet selectedadopted this new standard effective October 1, 2019 with no material impact to stock compensation issued to non-employees during the period during which it will implement this pronouncement, and it is currently evaluating the impact the adoption of ASU 2016-02 will have on its financial statements.

In March 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”). ASU 2016-09 simplifies several aspects of accounting for share-based payment award transactions, including income tax consequences, classification of awards as either liability or equity, and classification on the statement of cash flows. The standard is effective for annual periods beginning afterthree months ended December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently evaluating the impact the adoption of ASU 2016-09 will have on its financial statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments (a consensus of the Emerging Issues Task Force) (“ASU 2016-06”), which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts and requires that an entity assess the embedded call (put) options solely in accordance with the four-step decision sequence in ASC 815. ASU 2016-06 is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company is currently evaluating the impact the adoption of ASU 2016-06 will have on its financial statements.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.

Recent Tax and Financial Legislation

The Tax Cuts and Jobs Act of 2017 was signed into law on December 22, 2017 by President Donald J. Trump. The law includes significant changes to the U.S. corporate income tax system, including a Federal corporate rate reduction from 35% to 21%, limitations on the deductibility of interest expense and executive compensation, and the transition of U.S. international taxation from a worldwide tax system to a territorial tax system. We are in the process of analyzing the final legislation and determining an estimate of the financial impact.

NOTE 3 – OIL AND NATURAL GAS PROPERTIES

In March 2014 and 2015, theThe Company was awarded a total of 23currently has under lease four federal Outer Continental Shelf blocks and has licensed 2.2 million acres of three-dimensional (3-D) seismic data in its area of concentration.

The Company, as the operator of two wells drilled in the Central Gulf of Mexico.Mexico, has incurred tangible and intangible drilling costs for the wells in process and has billed its working interest partners for their respective share of the drilling costs to date. The intangible drilling and all other costs related to the first well have been impaired in the quarter ending June 30, 2020. The second well, Tau, was drilled to a measured depth of 15,254 feet, as compared to the originally permitted 29,857 foot measured depth. Producible hydrocarbon zones were not established to that depth, but hydrocarbon shows were encountered. Complex geomechanical conditions required two by-pass wellbores, one sidetrack wellbore, and eight casing strings to reach that depth. Equipment limitations prevented further drilling. In addition, the drilling rig had contractual obligations related to another operator. The Company elected to plug this well in a manner that would allow for re-entry at a later time. The Company is evaluating various options related to future operations in this wellbore and testing of the deeper Tau prospect. The Company plans to re-drill this prospect within the next twelve months, however, the impact of the CoVid-19 pandemic on offshore operations is still under mitigation by operators and will influence the potential timing of a re-drill.

In January 2019, the Tau well experienced an underground control of well event and as a result, the Company filed an insurance claim pursuant to its insurance policy with its insurance underwriters (the “Underwriters“). The total amount of the claim was approximately $10.8 million for 100% working interest after the insurance deductible amount. The Company received approximately $2.5 million of this amount and credited wells in process for approximately $0.9 million for the Company’s portion, and recorded an accrued payable for approximately $1.6 million, pending evaluation of distributions to the working interest owners. During the yearnine months ended SeptemberJune 30, 2016,2020, the accrued payable was settled by the issuance to the working interest partner of approximately 38.4 million shares of the Company’s common stock.

In May 2019, the Tau well experienced a second underground control of well event and as a result, the Company relinquished sixfiled an insurance claim. The Underwriters have acknowledged confirmation of these lease blocks.coverage, subject to the Policy terms and conditions, related to a subsurface well occurrence that happened during the drilling of the Company‘s Tau well on May 5, 2019, during drilling operations at a measured depth of 15,254 feet. The Company subsequently controlled the occurrence and ceased drilling operations and plugs were placed in the well to meet regulatory requirements prior to rig release. Pursuant to the Policy terms and conditions, the Underwriters were obligated to reimburse GulfSlope for qualified actual costs and expenses incurred to (i) regain control of the well, and (ii) restore or re-drill the well to 15,254 feet. Total costs and expenses to regain control of the well were estimated at approximately $4.8 million (net of deductible) for 100% working interest and approximately $4.8 million had been received as of June 30, 2020. GulfSlope’s share of this amount was approximately $1.2 million. Subsequent to the end of the reporting period, in July 2020, the Company reached agreement with the insurance Underwriters to accept a settlement in lieu of a re-drill (see Note 12 -Subsequent Events, for further discussion of this settlement).

In November 2019, an agreement was reached with a working interest partner whereby the working interest partner re-conveyed to the Company their 5% interest in Tau and Canoe in exchange for the release of claims and the Company foregoing collection of accounts receivable owed by the working interest partner. As a result of this agreement approximately $3.6 million of accounts receivable was reclassed to oil and gas properties – unproved during the nine months ended June 30, 2020.

As of June 30, 2020, the Company’s oil and natural gas properties consisted of unproved properties, wells in process and no proved reserves. During the three months ended June 30, 2020 and 2019, the Company capitalized lease costsapproximately $1.2 million and $0.4 million of $2,610,678 associated with these blocks were recorded asinterest expense to oil and natural gas properties, respectively, and approximately $0.3 million and $0.3 million of general and administrative expenses, capitalized to oil and natural gas properties, respectively. During the nine months ended June 30, 2020 and 2019, the Company capitalized approximately $2.3 million and $0.6 million of interest expense to oil and natural gas properties, respectively, and approximately $0.7 million and $0.6 million of general and administrative expenses, capitalized to oil and natural gas properties, respectively. Conversely, during the nine months ended June 30, 2020, the Company received certain credits totaling approximately $2.1 million (net to the Company’s interest) which the Company applied against oil and natural gas properties in the Condensed Balance Sheet.

During the three and nine months ended June 30, 2020 and 2019 the Company incurred impairment charges of approximately $2.1 million and $4.3 million, respectively resulting from the expiration of oil and natural gas properties. The Company also deducted $280,000 as an impairment of certain capitalized exploration costs that were directly allocable to the relinquished blocks, for a total impairment deduction of $2,890,678 for the year ended September 30, 2016.  During the year ended September 30, 2017, the Company relinquished six lease blocks. The capitalized lease costs of $2,054,212 associated with these blocks were recorded as impairment of oil and natural gas properties. The Company also deducted $1,262,000 as an impairment of certain capitalized exploration costs that were directly allocable to the 2017 relinquished blocks, for a total impairment deduction of $3,316,212. In September 2017, the Company was notified by Bureau of Ocean Energy Management (“BOEM”) that its August bid for an additional Outer Continental Shelf Block was accepted, and the block was awarded in October 2017. As of December 31, 2017 the Company holds twelve Outer Continental Shelf blocks.leases.

The Company paid $632,665 in gross annual lease rental payments to the BOEM for the year ended September 30, 2017. The Company’s share of these amounts are included in unproved properties.  In August 2017, the Company competitively bid on one block in the Central Gulf of Mexico Lease Sale 249 conducted by BOEM.  The Company was the high bidder on the block and paid $26,398, which represents 20% of the total lease bonus amount.  On September 29, 2017 the Company’s bid was accepted. After payment in October 2017 of, $140,591, which represents the remaining 80% lease bonus and first year rentals, the Company was awarded the lease block in October 2017. 

In August 2017, the Company entered into a letter agreement with Texas South Energy, Inc. (“TSE” or “Texas South”) that sets out the terms of a farm-out agreement for the Company’s Tau prospect. In exchange for $166,989, TSE will acquire an undivided 20% interest in the prospect. Through December 31, 2017, GulfSlope had received $166,989 in payments from TSE. In accordance with full cost requirements, the Company recorded the proceeds from the transaction as an adjustment to the capitalized costs of its oil & gas properties with no gain or loss recognition.

In October 2017, the Company executed the second amendment to the March 2014 farm-out agreement with Texas South under which Texas South will acquire 20% of Gulfslope’s interest in two prospects for $329,062. $150,000 of this amount has been paid through December 31, 2017.

For the year ended September 30, 2017, the Company incurred $172,094 in consulting fees, salaries and benefits, $195,125 in stock option costs associated with geoscientists, and $53,014 associated with technological infrastructure and third party hosting services. The Company capitalized these G&G costs because the Company owned specific unevaluated properties that these costs relate to. These capitalized amounts when added to the amount paid in 2017 for lease rental and lease acquisition payments of $402,766 and netted with the 2017 receipts from working interest portion of annual rentals of $118,679 and the amount received through September 30, 2017 for sale of working interest of $26,400 as well as the relinquished leases impairment amount of $3,316,212 results in unproved oil and gas properties of $1,887,879 reflected on the Company’s balance sheet at September 30, 2017.

For the quarter ended December 31, 2017, the Company incurred $68,631 in consulting fees and salaries and benefits associated with geoscientists, and $11,075 associated with technological infrastructure and third party hosting services. The Company capitalized these G&G costs because the Company owned specific unevaluated properties that these costs relate to. These amounts when added to unproved properties at September 30, 2017 and netted with the receipts to date from the sale of working interest result in $1,817,587 unproved properties at December 31, 2017.

In September 2017, GulfSlope Energy, Inc. announced that they had executed an exclusive letter of intent (“LOI”) with a large international oil and gas company (the “Partner”) and with Texas South to jointly drill and develop their oil and gas prospects located offshore Gulf of Mexico. In January 2018 the Company entered into a strategic partnership with Delek Group, Ltd, and Texas South and executed a participation agreement for a multi-phase exploration program.Under the terms of the Agreement, the Parties have committed to drill the Company’s “Canoe” and “Tau” prospects (the “Initial Phase”) with Delek having the option to participate in two additional two-well drilling phases and a final, three-well drilling phase (collectively, the “Phases”). In each Phase, Delek will earn a 75% working interest upon paying 90% of the exploratory costs associated with drilling each exploratory well. The Company will retain a 20% working interest while paying 8% of the exploratory costs associated with drilling each well. In addition, Delek will pay the Company approximately $1.1 million in cash for each Prospect when the exploration plan is filed with BOEM and/or BSEE. Also, each Party will be responsible for its pro rata share (based on working interest) of delay rentals associated with the Prospects. The Company will be the Operator during exploratory drilling of a Prospect, however, subsequent to a commercial discovery, Delek will have the right to become the Operator. Delek will have the right to terminate this Agreement at the conclusion of any drilling Phase. Delek will also have the option to purchase up to 5% of the Company’s common stock, par value $0.001 per share (the “Common Stock”), upon fulfilling its obligation for each Phase (maximum of 20% in the aggregate) at a price per share equal to a 10% discount to the 30-day weighted average closing price for the Common Stock preceding the acquisition. This option will expire January 8, 2020.

NOTE 4 – RELATED PARTY TRANSACTIONS

During April 2013 through September 2013,2017, the Company entered into convertible promissory notes whereby it borrowed a total of $6,500,000$8,675,500 from John Seitz, its currentthe chief executive officer.officer (“CEO“). The notes are due on demand, bear interest at the rate of 5% per annum, and $5,300,000 of the notes are convertible into shares of common stock at a conversion price equal to $0.12 per share of common stock (the then offering price of shares of common stock to unaffiliated investors). In May 2013, John Seitz converted $1,200,000 of the aforementioned debt into 10,000,000 shares of common stock, which shares were issued in July 2013. Between June of 2014 and December 2015, the Company entered into promissory notes whereby it borrowed a total of $2,410,000 from Mr. Seitz. The notes are not convertible, due on demand and bear interest at a rate of 5% per annum. During January through September 2017, the Company entered into promissory notes whereby it borrowed a total of $965,500 from Mr. Seitz. The notes are due on demand, bear interest at the rate of 5% per annum, and the outstanding principal and interest is convertible at the option of the holder into securities issued by the Company in a future offering, at the same price and terms received by unaffiliated investors. As of December 31, 2017June 30, 2020, the total amount owed to John Seitz our CEO, is $8,675,500. This amount is included in loans from related parties within the condensed balance sheets. There was a total of $1,312,139approximately $2.4 million of unpaid interest associated with these loans included in accrued interest payable within ourthe balance sheet as of December 31, 2017.

From August 2015 through February 2016 the Company entered into promissory notes whereby it borrowed a total of $267,000 from Dr. Ronald Bain, its current president and chief operating officer, and his affiliate ConRon Consulting, Inc. These notes are not convertible, due on demand and bear interest at the rate of 5% per annum. As of December 31, 2017, the total amount owed to Dr. Bain and his affiliate was $267,000. There was a total of $31,583 of accrued interest associated with these loans included within our balance sheet as of December 31, 2017. In June of 2016, Dr. Ronald Bain also entered into a $92,000 convertible promissory note with associated warrants (“Bridge Financing”) under the same terms received by other investors (see Note 5).

During March 2016, the Company entered into a promissory note for a total of $80,000 with the Morris Family Partnership, L.P., an affiliate of Mr. Paul Morris, a director of the Company. The note is due on demand and bears interest at the rate of 5% per annum and the principal amount is convertible at the option of the holder into securities issued by the Company in a future offering, at the same price and terms received by investors. The $80,000 promissory note was converted into the Bridge Financing (see Note 5).30, 2020.

On November 15, 2016, a family member of the CEO a related party, entered into a $50,000 convertible promissory note with associated warrants (“Bridge Financing”Financing“) under the same terms received by other investors (see Note 5).

Domenica Seitz CPA, related to John Seitz, has provided accounting consulting services to the Company. During the three month periodmonths ended December 31, 2017,June 30, 2020 and 2019, the services provided were valued at $5,915.approximately $15,000, respectively. During the nine months ended June 30, 2020 and 2019, the services provided were valued at approximately $45,000, respectively. The amount owed to this related party totals approximately $339,000 and $294,000 as of June 30, 2020 and September 30, 2019, respectively. The Company has accrued these amounts, and they have been reflected in related party payable in the December 31, 2017June 30, 2020 financial statements.

John Seitz has not received a salary since May 31, 2013, the date he commenced serving as our CEO and accordingly, no amount has been accrued on our financial statements.

Kevin Bain, son of Dr. Bain, is a geoscientist and an employee of the Company.  

NOTE 5 – BRIDGE FINANCINGNOTES PAYABLE

PPP Loan

On April 16, 2020, GulfSlope Energy, Inc. (the “Company“) entered into a promissory note (the “Note“) evidencing an unsecured $100,300 loan under the Paycheck Protection Program (the “PPP Loan“). The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act“) and is administered by the U.S. Small Business Administration. The PPP Loan is being made through Zions Bancorporation, N.A. dba Amegy Bank (the “Lender“). The PPP Loan is scheduled to mature on April 16, 2022 and has a 1.00% interest rate. No payments are due on the PPP Loan until November 16, 2020, although interest will continue to accrue during the deferment period. Beginning November 16, 2020, the Company will pay 18 equal monthly installments of principal and interest in the amount necessary to fully amortize the PPP Loan through the maturity date. Under the terms of the CARES Act, all or a portion of the PPP Loan may be forgiven. Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds for payroll costs and mortgage interest, rent or utility costs. No assurance is provided that the Company will obtain forgiveness of the PPP Loan in whole or in part. At June 30, 2020 accrued interest of approximately $200 was included in accrued interest payable in the June 30, 2020 financial statements.

NOTE 6 – CONVERTIBLE PROMISSORY NOTES WITH ASSOCIATED WARRANTSPAYABLE

Bridge Financing Notes

Between June and November 2016, the Company issued eleven convertible promissory notes (“Bridge Financing Notes“) with associated warrants in a private placement to accredited investors for total gross proceeds of $837,000. Three of the$837,000, including $222,000 from related parties. These notes were to related parties for proceeds totaling $222,000, including the extinguishment of $70,000 worth of related party payables. The convertible notes havehad a maturity of one year bear(which has been extended at maturity to April 30, 2020 and was extended again during the nine months ended June 30, 2020 to April 30, 2021), an annual interest rate of 8% and can be converted at the option of the holder at a conversion price of $0.025 per share. In addition, the convertible notes will automatically convert if a qualified equity financing of at least $3 million occurs before maturity and such mandatory conversion price will equal the effective price per share paid in the qualified equity financing. The remaining note balances as of June 30, 2020 and September 30, 2019 were $277,000, with remaining unamortized debt discounts of approximately $16,000 and $100,000, respectively. Debt discount amortization for the three and nine months ended June 30, 2020 was approximately $17,000 and $103,000, respectively. Debt discount amortization for the three and nine months ended June 30, 2019 was approximately $9,000. Accrued interest as of June 30, 2020 related to these notes was approximately $88,000. As noted above, the maturity date related to these notes and associated warrants was extended to April 30, 2021. In addition toconsideration for the convertibleextension of the notes, the investors received 27.9 million warrants (7.4 million toCompany extended the above mentioned related parties) with an exercise price of $0.03 and a term of the earlierrelated warrants until April 30, 2021 and recognized $19,300 of three yearsadditional debt discount which represented the incremental value of the modified warrants over the pre-modification warrants.

Delek Note

On March 1, 2019, the Company entered into a term loan agreement with Delek, where Delek agreed to provide the Company with multiple draw term loans in an aggregate stated principal amount of up to $11.0 million, of which $10.0 million was initially advanced and subsequently converted to equity through the exercise of a warrant. The maturity date of the facility was September 4, 2019, and until such time any loans would bear interest at a rate per annum equal to 5.0% or 7% upon the occurrence of default. Amounts outstanding under the Term Loan Agreement are secured by a changesecurity interest in substantially all of control.the properties and assets of the Company. On April 19, 2019, the Company borrowed the remaining $1.0 million under this agreement.

The term loan facility expired as of September 4, 2019, and in October 2019, the Company signed a Post-Drilling Agreement with Delek modifying this arrangement. The Post-Drilling Agreement states that as payoff for the Company’s outstanding obligations of $1,000,000 plus accrued interest (and additional fees of approximately $200,000), the Company shall issue a convertible note payable to Delek in the amount of $1,220,548. The new note is convertible at the option of Delek at a conversion price of $0.05 per share, and in the event of default the conversion rate adjusts to 60% of the lowest volume weighted average price in the previous 20 trading days. Interest on the note accrues at 12% per annum (15% upon default) and the maturity of the note is October 22, 2020. The Company evaluatedhas a right to prepay all principal and accrued interest prior to maturity. As of June 30, 2020, the various financial instrumentsaccrued interest payable related to this note was approximately $103,000.

The Company accounted for the October 2019 transaction as an extinguishment of the prior note given the addition of the substantive conversion feature discussed above. In addition, The Company concluded that the embedded conversion feature within the note requires derivative accounting treatment under ASC 480815, Derivatives and ASC 815 and determined no instruments or featuresHedging due to the potential variable conversion feature which lacks an explicit limit on the number of shares that may be required fair value accounting. Therefore, in accordance with ASC 470-20-25-2,upon conversion. Accordingly, the Company allocatedvalued the proceeds between the convertible notes and warrants based on their relative fair values. This resulted in an allocation of $452,422 to the warrants and $384,368 to the convertible notes. After such allocation, the Company evaluated the conversion option to discern whether a beneficialembedded conversion feature existed based upon comparing the effective exercise priceand host instrument at their fair values of the convertible notes to the$479,498 and $1,220,548, respectively, and recognized a loss on extinguishment of $676,785. The fair value of the shares they are convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $384,368. Accordingly,host note was determined by discounting the debt discount associated with these notes was $836,790. Such discount was amortized using the effective interest rate method over the term (one year) of the convertible notes. For the quarter ended December 31, 2017 the amortization of this discount and the discount associated with the extension warrants (see below) totaled $26,970, and is included in interest expense in the statement of operations. Accrued interest expense for the quarter ended December 31, 2017 was $16,740.  Cumulative accrued interest expense at December 31, 2017 was $98,804.

Upon maturity of eight of the eleven promissory notes in June 2017, the Company issued 3,225,000 extension warrants (equal to 25% of the original warrant amount) to the holders of the notes to extend the terms to January 15, 2018. The Company evaluated this modification including considering the fair value of the warrants issued and concluded that extinguishment accounting was required as the present value of future cash flows from the new note, including the fair value of the warrants issued to extend, exceeded the present value of future cash flows of the old note by more than 10%.at a market participant-based rate of interest. Further, since the embedded conversion feature is a derivative liability, it is subsequently remeasured to fair value each reporting period. The fair value of the warrantsembedded conversion option was deemed to be $50,701 and such amount was recognized immediatelyapproximately $6,300 as a loss on extinguishment of debt. June 30, 2020.

The fair value of the warrantsembedded conversion feature was determined usingutilizing a Geometric Brownian Motion Stock Path Based Monte Carlo Simulation that utilized the Black-Scholesfollowing key assumptions:

June 2019 Convertible Debenture

On June 21, 2019, the Company entered into a securities purchase agreement to borrow up to $3,000,000 through the issuance of convertible debentures (“Convertible Debentures”) and associated warrants. On June 21, 2019, approximately $2,100,000 (“Tranche 1”) of Convertible Debentures were purchased with other tranches closing on August 7, 2019 for $400,000 (“Tranche 2”) and November 6, 2019 (“Tranche 3”) for $500,000. All tranches accrue interest at eight percent per annum, and mature one year after each respective closing date, and are convertible at the option pricing model.of the holder any time after issuance into common stock at a conversion rate of the lesser of: (1) $0.05 per share; or (2) 80% of the lowest volume weighted adjusted price (as reported by Bloomberg, LP) for the ten consecutive trading days immediately preceding conversion, and in the event of default the conversion rate adjusts to 60% of the lowest volume weighted average price in the previous 20 trading days.

In July and August 2017,addition, the three remaining promissory notes issued in July, August and November 2016 were extended until January 15, 2018 and issued 3,750,000 extensionholder received warrants (equal to 25%purchase an aggregate of the original warrant amount). The Company evaluated this transaction including considering the fair value of the warrants issued and concluded that modification accounting was required as the present value of future cash flows from the new note, including the fair value of the warrants issued to extend, are less than 10% of the present value of future cash flows of the old note. When an instrument is modified, any incremental increase in value (in this case the warrants) should be added to the discount of the notes and such discount should be amortized to interest expense using the effective interest rate method over the new remaining life of the note. The fair value of the warrants, $38,946, was determined using the Black-Scholes option pricing model.☐

On December 28, 2016, the Company issued a convertible promissory note with 500,000 shares of restricted stock and 550,000 warrants in a private placement to an accredited investor for $50,000 in proceeds. The warrants have a five year term and an exercise price of $0.10. The promissory note has a face value of $55,555, which includes 10% original issue discount (“OID”) and incurs a one-time upfront interest charge of six percent. The holder of the note has the option to convert the note into50 million shares of common stock at a conversionan exercise price of $0.02$0.04 per share. Approximately $450,000Such warrants expire on the fifth anniversary of additional funding is available under similar terms ifissuance. In total the Company and the lender mutually agreeoffering costs incurred related to further tranches. this Convertible Debenture were approximately $398,000.

The Company evaluated the various financial instruments under ASC 480conversion feature and ASC 815concluded that it should be bifurcated and determined no material instruments or featuresaccounted for as a derivative liability due to the variable conversion feature which does not contain an explicit limit on the number of shares that are required to be issued upon conversion. In addition, the Company concluded the warrants required treatment as derivative liabilities as the Company could not assert it has sufficient authorized but unissued shares to settle the warrants upon exercise when taking into account other stock-based commitments including the Convertible Debentures. Accordingly, the embedded conversion feature and warrants were recorded at fair value accounting. Therefore, in accordance with ASC 470-20-25-2,at issuance and are subsequently remeasured to fair value each reporting period. The Company recognized gains of approximately $183,000 and $1,243,000 for the Company allocated the proceeds between the convertible note, restricted common stock,three and warrants based on their relative fair values. This resulted in an allocation of $8,460nine months ended June 30, 2020, related to the restricted stock, $7,969 to the warrants and $33,571 to the convertible note. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible note to thechange in fair value of the shares it is convertible into. The Company concluded a beneficialembedded conversion feature existed and measured such beneficial conversion feature at $33,571. Accordingly, at December 28, 2016,warrants, respectively.

In June 2020, the Company extended the maturity dates of Tranche 1 and Tranche2 to August 21, 2020 in exchange for a cash payment of $50,000. The extension was treated as a modification for accounting purposes which resulted in the $50,000 being recognized as an additional debt discount associated with these notes was $55,555. Such discount was amortized using the effective interest rate method over the term (seven months) of the convertible note. For the year ended September 30, 2017 amortization of this discount totaled $55,555allocated on a pro-rata basis between Tranche 1 and is included in interest expense in the statement of operations. Accrued interest expense for the year ended September 30, 2017 is $3,333. The note, related OIDTranche 2 and accrued interest were converted into approximately 5.5 million shares of GulfSlope Energy common stock in a series of conversions beginning on July 10, 2017 and ending with a conversion on September 18, 2017 on which date all were paid in full.

On March 14, 2017, the Company issued a convertible promissory note with 1,000,000 shares of restricted stock and 1,100,000 warrants in a private placement to an accredited investor for $100,000 in proceeds. The warrants have a five-year term and an exercise price of $0.10. The promissory note has a face value of $111,111, which includes 10% original issue discount (“OID”), and incurs a one-time upfront interest charge of six percent. The holder of the note has the option to convert the note into shares of common stock at a conversion price of $0.02 per share. Approximately $350,000 of additional funding is available under similar terms if the Company and the lender mutually agree to further tranches. The Company evaluated the various financial instruments under ASC 480 and ASC 815 and determined no material instruments or features required fair value accounting. Therefore, in accordance with ASC 470-20-25-2, the Company allocated the proceeds between the convertible note, restricted common stock, and warrants based on their relative fair values. This resulted in an allocation of $17,250 to the restricted stock, $14,051 to the warrants and $68,699 to the convertible note. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible note to the fair value of the shares it is convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $68,699. Accordingly, at March 14, 2017, the debt discount associated with these notes was $111,111. Such discount will be amortized using the effective interest rate method over the term (seven months)remaining life of the convertible note. Forrespective tranches.

In addition, during the yearnine months ended SeptemberJune 30, 2017 amortization2020, the lender converted approximately $1,100,000 of this discount totaled $105,841principal of Tranche 1 and is included in interest expense in the statementapproximately $139,000 of operations. Accrued interest expense for the year ended September 30, 2017 is $6,666. In September 2017, $30,000 was converted into 1.5 million shares of stock, leaving a note balance of $81,111 at September 30, 2017. In October 2017, the note balance of $81,111 and accrued interest of $6,600 were converted into approximately 4.3 million shares of GulfSlope Energy common stock. During the quarter ended December 31, 2017 the note and all accrued interest were paid in full.

On October 16, 2017, the Company issued a convertible promissory note with 1,000,000 shares of restricted stock and 1,100,000 warrants in a private placement to an accredited investor for $100,000 in proceeds. The warrants have a five-year term and an exercise price of $0.10. The promissory note has a face value of $110,000, which includes 10% original issue discount (“OID”), and incurs a one-time upfront interest charge of six percent. The holder of the note has the option to convert the note into shares of common stock issued was recorded at a conversion price of $0.02 per share. Approximately $250,000 of additional funding is available under similar terms if the Company and the lender mutually agree to further tranches. The Company evaluated the various financial instruments under ASC 480 and ASC 815 and determined no material instruments or features requiredits fair value accounting. Therefore, in accordance with ASC 470-20-25-2,on the Company allocated the proceeds between the convertible note, restricted common stock, and warrants based on their relative fair values. This resulted in an allocationdates of $21,287 to the restricted stock, $20,175 to the warrants and $58,538 to the convertible note. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible note to the fair value of the shares it is convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $58,538. Accordingly, at October 16, 2017, the debt discount associated with these notes was $110,000. Such discount will be amortized using the effective interest rate method over the term (seven months) of the convertible note. For the quarter ended December 31, 2017 amortization of this discountwhich totaled $39,434 and is included in interest expense in the statement of operations. Accrued interest expense for the quarter ended December 31, 2017 is $6,600.

On December 15, 2017, the Company issued a convertible promissory note with 1,000,000 shares of restricted stock and 1,100,000 warrants in a private placement to an accredited investor for $100,000 in proceeds. The warrants have a five-year term and an exercise price of $0.10. The promissory note has a face value of $110,000, which includes 10% original issue discount (“OID”), and incurs a one-time upfront interest charge of six percent. The holder of the note has the option to convert the note into shares of common stock at a conversion price of $0.02 per share. Approximately $150,000 of additional funding is available under similar terms if the Company and the lender mutually agree to further tranches. The Company evaluated the various financial instruments under ASC 480 and ASC 815 and determined no material instruments or features required fair value accounting. Therefore, in accordance with ASC 470-20-25-2, the Company allocated the proceeds between the convertible note, restricted common stock, and warrants based on their relative fair values. This resulted in an allocation of $27,807 to the restricted stock, $27,212 to the warrants and $44,981 to the convertible note. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible note to the fair value of the shares it is convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $44,981. Accordingly, at December 15, 2017, the debt discount associated with these notes was $110,000. Such discount will be amortized using the effective interest rate method over the term (seven months) of the convertible note. For the quarter ended December 31, 2017 amortization of this discount totaled $8,302 and is included in interest expense in the statement of operations. Accrued interest expense for the quarter ended December 31, 2017 is $6,600.

NOTE 6 – COMMON STOCK/PAID IN CAPITAL  

As discussed in Note 5, between June and November 2016, the Company issued 27.9approximately $2.1 million warrants in conjunction with convertible notes payable. The warrants have an exercise price of $0.03 and a termloss on extinguishment of the earlier of 3 years or upon a change of control. Based upon the allocation of proceeds between the convertible notes payabledebt and the warrants,related derivative liability was recognized for approximately $452,422 was allocated to the warrants. During June through August 2017, the maturity date of all of the Bridge Financing Notes was extended to January 15, 2018 in exchange for the issuance of 25% additional warrants. The warrants have an exercise price of $0.03 and the same expiration date (three years from original transaction) as the original warrants.$1.0 million.

The fair value of the warrants wereembedded conversion feature was determined using the Black Scholes valuation model withutilizing a Geometric Brownian Motion Stock Path Based Monte Carlo Simulation that utilized the following key assumptions:

(1) Fair market value onIn addition to the datefixed exercise price noted above, the model incorporates the variable conversion price which is simulated as 80% of agreement the lowest trading price within the ten consecutive days preceding presumed conversion.

The Company’s convertible promissory notes consisted of the following as of June 30, 2020.

NOTE 7 – FAIR VALUE MEASUREMENT

Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company’s derivative financial instruments that were accounted for at fair value on a recurring basis as of June 30, 2020:

The change in derivative financial instruments for the nine months ended June 30, 2020 is as follows:

Non-recurring fair value assessments include impaired oil and natural gas property assessments and stock-based compensation. During the period December 2016 through December 2017nine months ended June 30, 2020, the Company issued 3,500,000 sharesrecorded an impairment charge of restricted stock$2,124,885 and stock-based compensation expense of approximately $968,000, of which approximately $498,000 was capitalized to Lucas Hoppel as part of financing transactions (see Note 5).oil and gas properties.

NOTE 8 – COMMON STOCK/PAID IN CAPITAL

As discussed in Note 5, in December 2016,6, the Company issued 550,000 warrants in conjunctionapproximately 106 million common shares with a convertible note payable. The warrants have an exercise pricefair value of $0.10 and a termapproximately $2.1 million upon partial conversions of the earlier of 5 years or upon a change of control. Basednotes and related accrued interest during the nine months ended June 30, 2020. The common shares were valued based upon the allocation of proceeds betweenclosing common share prices on the convertible note payable andrespective conversion dates.

In addition, during the warrants, approximately $13,188 was allocated to the warrants. In March 2017,nine months ended June 30, 2020, the Company issued 1,100,000 warrants in conjunction38,423,221 common shares with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $14,051 was allocated to the warrants. In October 2017, the Company issued 1,100,000 warrants in conjunction with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $20,175 was allocated to the warrants. In December 2017, the Company issued 1,100,000 warrants in conjunction with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $27,212 was allocated to the warrants.

The fair value of $1,536,929 to extinguish an accrued expense that totaled $1,613,775. The common shares were valued based upon the warrants were determined usingclosing common share price on the Black Scholes valuation model withdate of settlement resulting in a gain on the following key assumptions:  extinguishment of the obligation of approximately $77,000.

NOTE 7–9 – STOCK-BASED COMPENSATION

During the nine months ended June 30, 2020, upon the passing of a member of the management team, the Company modified the vesting terms of a stock option grant previously made to this individual which vested the instrument immediately. The option was for three million shares and was originally granted in June 2018. The Company recorded approximately $8,000 in additional compensation expense related to this modification.

Stock-based compensation cost is measured at the grant date, based on the estimated fair value of the award using the Black Scholes option pricing model, and is recognized over the required vesting period. The Company recognized $93,381approximately $240,000 and $0$393,000 in stock-based compensation duringexpense for the three monthsquarters ended December 31, 2017,June 30, 2020 and December 31, 2016,2019, respectively. For the three months ended December 31, 2017, aA portion of these costs, $27,875approximately $124,000 and $207,000 were capitalized to unproved properties for the three months ended June 30, 2020 and 2019, respectively, with the remainder were recorded as general and administrative expenses.expenses for each respective period. The Company recognized approximately $968,000 and $802,000 in stock-based compensation expense for the nine months ended June 30, 2020 and 2019, respectively. For the nine months ended June 30, 2020 and 2019 approximately $498,000 and $542,000, respectively was capitalized to unproved properties. The Company did not issue any new stock option grants during the nine months ended June 30, 2020.

The following table summarizes the Company’s stock option activity during the threenine months ended December 31, 2017:June 30, 2020:

Stock-based compensation cost is measured at the grant date, based on the estimated fair value of the award, and is recognized over the required vesting period.  For the quarter ended December 31, 2017 and 2016 there was $93,381 and $0 in stock-based compensation cost, respectively. For the quarter ended December 31, 2017 a portion of these costs, $27,875, were capitalized to unproved properties and the remainder were recorded as general and administrative expenses.

The intrinsic value of the options outstanding as of December 31, 2017 was $1.2 million.  As of December 31, 2017June 30, 2020, there was no unrecognized stock-based compensation.compensation expense.

NOTE 810 – COMMITMENTS AND CONTINGENCIES

In March 2013, theThe Company licensed certain seismic data pursuant toreached an agreement in August 2018 for $4,012,260. Asthe settlement of December 31, 2017, the Company has paid $3,009,195approximately $1 million in debt. Payment of approximately $0.16 million in cash and 10 million shares of common stock was made. The agreement contains a provision that upon the sale of the common stock if the original debt is obligatednot fully satisfied, full payment will be made under a mutually agreed payment plan. If the stock is sold for a gain any surplus in excess of $1.3 million shall be a credit against future purchases. The agreement was determined to pay $1,003,065 during fiscal 2018.meet the definition of a derivative in accordance with ASC 815. At June 30, 2020, there is a derivative financial instrument liability recorded of approximately $0.8 million related to this agreement.

In October 2017,November 2019, the Company purchased a directors and officers’ insurance policy for $171,360approximately $241,000 and financed $156,718approximately $220,000 of the premium by executing a note payable.payable at an interest rate of 5.6%. The balance of the note payable at December 31, 2017as of June 30, 2020, is $128,807.approximately $82,000 and is included in the Notes Payable balance in the Condensed Balance Sheet.

NOTE 11 – LEASES

Effective October 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842), and all related amendments (“ASC 842“) using the modified retrospective approach. In July 2018, the FASB approved an optional transition method that removed the requirement to restate prior period financial statements upon adoption of the standard with a cumulative-effect adjustment to retained earnings in the period of adoption and we elected to apply this transition method. As a result, the comparative period information has not been restated and continues to be reported under the accounting standards in effect for the period presented. The adoption of ASC 842 had no impact to our previously reported results of operations or cash flows. 

The following table depicts the cumulative effect of the changes made to our September 30, 2019 balance sheet for the adoption of ASC 842 effective on October 1, 2019:

The adoption of ASC 842 primarily resulted in the recognition of operating lease liabilities totaling $130,679, based upon the present value of the remaining minimum rental payments using discount rates as of the adoption date. In addition, we recorded corresponding right-of-use assets totaling $104,363 based upon the operating lease liabilities adjusted for deferred rent and lease incentives. In addition, we recorded a $16,431 cumulative effect of initially adopting ASC 842 as an adjustment to the opening balance of accumulated deficit.

NOTE 912 – SUBSEQUENT EVENTS

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.

On January 8, 2018, GulfSlope Energy, Inc. (the “Company”)July 27, 2020, the Company entered into an agreement with holders of the Convertible Debentures to modify the existing arrangement. At the date of modification, the remaining principal under the Convertible debentures was $1.9 million. Pursuant to the modified agreement, the payment terms were changed to as follows:

Upon the timely payment by the Company of the amounts set forth above, all other amounts due on the Debentures, including any interest or fees accrued or that will accrue or become due or payable on the Debentures, will be extinguished.

In addition, the holder agreed to limit their conversion right to $300,000 of outstanding principal between the date of modification and November 30, 2020. The Company further agreed to reduce the exercise price on the warrants to purchase 50,000,000 shares of common stock held by the holder from $0.04 per share to $0.02 per share. The Company plans to use a portion of the proceeds from the insurance settlement, discussed below, to make the payments set forth above.

On July 27, 2020, the Company entered into a participation agreement (the “Agreement”)settlement with Delek GOM Investments, LLC,the Underwriters of a subsidiary of Delek Group Ltd. (“Delek”), and Texas South Energy, Inc. (“Texas South”) (collectively, the “Parties”) for the Company’s interests in its Gulf of Mexico oil and gas leases (the “Farm-out”). The Agreement sets out the terms and conditions of the Parties’ participation inwell control events insurance policy covering certain claims associated with the drilling of a multi-phase exploration program targeting the Company’s prospects (the “Prospects”) locatedTau Prospect during May 2019. In accordance with the settlement, in lieu of the insurer paying for the redrill of the well and for a complete release of any further liability under the insurance policy, the Company will receive $6,575,000 in cash net to its 25% working interest. Approximately $6.0 million of this amount has been received through the filing date of this report. The Company intends to apply the proceeds from the insurance settlement to pay amounts due on the Company’s existing leases (the “Leases”). Under the terms of the Agreement, the Parties have committed to drill the Company’s “Canoe”Convertible Debentures and “Tau” prospects (the “Initial Phase”) with Delek having the option to participate in two additional two-well drilling phases and a final, three-well drilling phase (collectively, the “Phases”). In each Phase, Delek will earn a 75% working interest upon paying 90% of the exploratory costs associated with drilling each exploratory well. The Company will retain a 20% working interest while paying 8% of the exploratory costs associated with drilling each well. In addition, Delek will pay the Company approximately $1.1 million in cash for each Prospect exploration plan filed with BOEM and/or BSEE. Also, each Party will be responsible for its pro rata share (based on working interest) of delay rentalsother payables, as well as fund other general corporate purposes including expenditures associated with the Prospects. The Company will be the Operator during exploratoryCompany’s drilling of the Prospect, however, subsequent to a commercial discovery, Delek will have the right to become the Operator. Delek will have the right to terminate this Agreement at the conclusion of any drilling Phase. Delek will also have the option to purchase up to 5% of the Company’s common stock, par value $0.001 per share (the “Common Stock”), upon fulfilling its obligation for each Phase (maximum of 20% in the aggregate) at a price per share equal to a 10% discount to the 30-day weighted average closing price for the Common Stock preceding the acquisition. This option will expire January 8, 2020. The foregoing description of the Agreement does not purport to be a complete description of the terms, provisions and conditions of such document, and represents only a summary of certain of the principal terms, provisions and conditions thereof. The Company will assign an eight-tenths of one percent of eight/eights net profits interest in certain of the Company’s oil and gas leases to include Vermilion Area, South Addition 378, Ship Shoal Area, South Addition 336, and Ship Shoal Area, South Addition 351, to Hi-View Investment Partners, LLC (“Hi-View”) in consideration for consulting services provided pursuant to a non-exclusive consulting engagement dated October 25, 2017, by and between Hi-View, the Company, and Texas South (the ”Advisory Agreement”). Hi-View will be entitled to additional assignments on the same terms and conditions as described above related to any of the Leases whereby Delek elects to participate in drilling of an exploratory well. In addition, the Company issued an aggregate of eighty million shares of Common Stock to Hi-View in consideration for consulting services provided pursuant to the Advisory Agreement. In the event that Delek has not funded the approximately one million one hundred thousand payment referenced above within six months of execution of this Agreement, then the Common Stock will be returned by Hi-View to the Company.

program.

On January 1, 2018, the Company executed the third amendment to the March 2014 farm-out agreement with Texas South under which Texas South will acquire 20% of GulfSlope’s interest in two prospects for $225,000.

In January 2018 the maturity date of convertible promissory notes (bridge financing) that matured on January 15, 2018 was extended to April 16, 2018 in exchange for 2.79 million additional warrants.

In February 2018, the Company executed a drilling rig contract with Atlantic Maritime Services LLC, a wholly owned subsidiary of Rowan Companies plc, to secure and utilize the Rowan Ralph Coffman jackup drilling rig for the Company’s 2018 Gulf of Mexico drilling program.GulfSlope anticipates spudding the first well in mid-2018 on Vermilion Area, South Addition Block 378 (Canoe Shallow prospect) and the second well on Ship Shoal Area, South Addition Blocks 336 / 351 (Tau prospect) shortly thereafter. Initial drilling on both prospects is expected to be completed before the end of the year.The Ralph Coffman is a high specification jackup rig that can drill to 35,000 feet. The rig is currently being mobilized from Trinidad and is anticipated to arrive in the Gulf of Mexico shortly.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-looking Statements

The following discussion highlights the principal factors that have affected our financial condition and results of operations as well as our liquidity and capital resources for the periods described. This discussion contains forward-looking statements. Please see “Forward-Looking Statements”Statements“ above.

Historical Operations

GulfSlope Energy, Inc. is an independent oil and natural gas exploration and production company whose interests are concentrated in the United States, Gulf of Mexico federal waters offshore Louisiana.Louisiana in 450 feet or less of water depth. The Company has leased twelveunder lease four federal Outer Continental Shelf blocks (referred to as “leases”“leases“ in this report) and licensed 2.2 million acres (440 blocks) of three-dimensional (3-D) seismic data in its area of concentration. Approximately half of this data has been reprocessed utilizing Reverse Time Migration (RTM) to more accurately define the imaging below salt. Since March 2013, we have been singularly focused on identifying high-potential oil and natural gas prospects located on the shelf in the U.S. GOM. We have evaluated our licensed 3-D seismic data using advanced interpretation technologies. As a result of these analyses, we have identified and acquired leases on multiple prospects that we believe may contain economically recoverable hydrocarbon deposits, and we plan to continue to conduct more refined analyses of our prospects as well as target additional lease and property acquisitions. We have given preference to areas with water depths of 450 feet or less where production infrastructure already exists, which will allow for any discoveries to be developed rapidly and cost effectively with the goal to reduce economic risk while increasing returns. Actions of the Bureau of Ocean Energy Management (“BOEM“) have reduced the royalty rate for leases acquired after August 2017 in water depths of less than 200 meters (approximately 656 feet) from 18.75% to 12.5%, which further enhances the economics for the drilling of any leases acquired after August 2017 in these water depths. This reduced royalty applies to three of the Company’s leases.

The Company has invested significant technical person hours in the proprietaryreprocessing and interpretation and the associated high-end reprocessing of this seismic data. The result of this proprietary interpretation has been the identification of multiple prospects that we believe may have substantial potential hydrocarbon deposits. Based on this analysis, we currently have twelve blocks under lease in the federal waters of Offshore Gulf of Mexico. We believe the proprietary reprocessing and interpretation and the contiguous nature of our licensed 3-D seismic data gives us an advantage over other exploration and production (“E&P”) companies operating in our focuscore area. We have identified nine prospects that are covered by our leases and throughout this Report we refer to these acquired leases as our “portfolio.”

In March 2014 and 2015, we participated in the Central Gulf of Mexico Lease Sales 231 and 235 and were awarded twenty-three blocks through a competitive bid process.  After evaluating our leasehold position we relinquished six lease blocks in 2016 and six lease blocks in 2017. In August 2017 we competitively bid at the Central Gulf of Mexico Lease Sale 249 and were awarded one block, leaving the Company with twelve Outer Continental Shelf blocks, and nine prospects that we believe may contain economically recoverable hydrocarbon deposits.

Through December 31, 2017, we have spent approximately $26.5 million on the acquisition, reprocessing, and interpretation of seismic data associated with our seismic license agreements and these costs were capitalized as oil and gas exploration costs which are subject to periodic evaluation for impairment. Approximately $19.5 million of these seismic-related expenses were impaired for accounting purposes. Approximately $7.0 million of our exploration expenditures remain capitalized. These capitalized exploration costs when added with our lease acquisition and annual lease rental costs of $10.5 million and netted with the $11.0 million received from the sale of working interests and the impairment of relinquished leases of $4.7 million, results in the $1.8 million reflected as Unproved Oil and Natural Gas Properties on our Condensed Balance Sheet as of December 31, 2017.

We have historically operated our business with working capital deficits and these deficits have historically been funded by equity and debt investments and loans from management. As of December 31, 2017,June 30, 2020, we had $0.1$1.06 million of cash on hand.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$10.0 million to meet its obligations and planned expenditures through February of 2019.August 2021. The Company plans to finance its operations and planned expenditures through the issuance of equity andand/or debt financings.financings, farm-out agreements, and/or other transactions. There are no assurances that financing will be available with acceptable terms, if at all.

Competitive Advantages

Experienced management. Our management has significant experience in finding and developing oil and natural gas. Our team has a track record of discovering and developing multi-billion dollar projects worldwide. The Company’s management team has over 200 years of combined industry experience exploring, discovering, and developing oil and natural gas. We successfully deployed a technical team with over 150 years of combined industry experience exploring for and developing oil and natural gas in the development and execution of our technical strategy. We believe the application of advanced geophysical techniques on a specific geographic area with unique geologic features such as conventional reservoirs whose trapping configurations have been obscured by overlying salt layers provides us with a competitive advantage.

Advanced seismic image processing. Commercial improvements in 3-D seismic data imaging and the development of advanced processing algorithms, including pre-stack depth, beam, and reverse time migration have allowed the industry to better distinguish hydrocarbon traps and identify previously unknown prospects. Specifically, advanced processing techniques improve the definition of the seismic data from a scale of time to a scale of depth, thus correctly locating the images in three dimensions. Our technical team has significant experience utilizing advanced seismic image processing techniques in our core area, and we apply the industry’s most advanced noise reduction technology to generate clearer images. In addition, having drilled two wells in our core area, we have the advantage of proprietary velocity information which further enhances our depth migration of 3D seismic data. This enables more accurate subsurface imaging.

Industry leading position in our core area. We have licensed 2.2 million acres of 3D seismic data which covers over 440 OCS Federal lease blocks on the highly prolific Louisiana outer shelf, offshore Gulf of Mexico. We believe the proprietary and state-of-the-art reprocessing of our licensed 3-D seismic data, along with our proprietary and leading-edge geologic depositional reservoir sand and petroleum trapping models, gives us an advantage in assembling a high-quality drilling portfolio in our core area. We continuously work to identify additional leasing opportunities to further enhance our drilling portfolio.

Technical Strategy

We believe that a major obstacle to identifying potential hydrocarbon accumulations globally has been the inability of seismic technology to accurately image deeper geologic formations because of overlying massive, extensive, and complex salt bodies. Large and thick laterally extensive subsurface salt layers highly distort the seismic ray paths traveling through them, which often has led to misinterpretation of the underlying geology and the potential major accumulations of oil and gas. We believe the opportunity exists for a technology-driven company to extensively apply advanced seismic acquisition and processing technologies, with the goal of achieving attractive commercial discovery rates for exploratory wells, and their subsequent appraisal and development, potentially having a very positive impact on returns on invested capital. These tools and techniques have been proven to be effective in deep water exploration and production worldwide, and we are using them to drill targets below the salt bodies in an area of the shallower waters of the GOM where industry activity has largely been absent for over 20 years. In fact, GulfSlope management led the early industry teams in their successful efforts to discover and develop five new fields below the extensive salt bodies in our core area during the 1990’s, which have produced over 125 million barrels of oil equivalent. 

Our technical approach to exploration and development is to deploy a team of highly experienced geo-scientists who have current and extensive understanding of the geology and geophysics of the petroleum system within our core area, thereby decreasing the traditional timing and execution risks of advancing up a learning curve. For data licensing, re-processing and interpretation, our technical staff has prioritized specific geographic areas within our 2.2 million acres of seismic coverage, with the goal to optimize initial capital outlays.

Modern 3-D seismic datasets with acquisition parameters that are optimal for improved imaging at multiple depths are readily available in many of these sub-basins across our core area, and they can be licensed on commercially reasonable terms. The application of state-of-the-art seismic imaging technology is necessary to optimize delineation of prospective structures and to detect the presence of hydrocarbon-charged reservoirs below many complex salt bodies. An example of such a seismic technology is reverse time migration, which we believe to be the most accurate, fastest, and yet affordable, seismic imaging technology for critical depth imaging available today.

Lease and Acquisition Strategy

Our prospect identification and analytical strategy is based on a thorough understanding of the geologic trends within our core area. Exploration efforts have been focused in areas where lease acquisition opportunities are readily available. We entered into two master 3-D license agreements, together covering approximately 2.2 million acres and we have completed advanced processing on select areas within this licensed seismic area exceeding one million acres. We can expand this coverage and perform further advanced processing, both with currently licensed seismic data and seismic data to be acquired. We have sought to acquire and reprocess the highest resolution data available in the potential prospect’s direct vicinity. This includes advanced imaging information to further our understanding of a particular reservoir’s characteristics, including both trapping mechanics and fluid migration patterns. Reprocessing is accomplished through a series of model building steps that incorporate the geometry of the geology to optimize the final image. Our integration of existing geologic understanding and enhanced seismic processing and interpretation provides us with unique insights and perspectives on existing producing areas and especially underexplored formations below and adjacent to salt bodies that are highly prospective for hydrocarbon production.

We currently hold four leases that comprise three prospects and we intend to evaluate additional potential sources for growth opportunities with companies that hold active leases in our core area. Our leases have a five-year primary term, expiring in 2022 and 2023 and 2025. BOEM’s regulatory framework provides multiple options for leaseholders to apply to receive extensions of lease terms under specified conditions. GulfSlope is exploring all options contained in BOEM’s regulatory framework to extend the terms of the leases. Additional prospective acreage can be obtained through lease sales, farm-in, or purchase. As is consistent with a prudent and successful exploration approach, we believe that additional seismic licensing, acquisition, processing, and/or interpretation may become highly advantageous, in order to more precisely define the most optimal drillable location(s), particularly for development of discoveries.

We continue to evaluate potential producing property acquisitions in the offshore GOM, taking advantage of our highly specialized subsurface and engineering capabilities, knowledge, and expertise to identify attractive opportunities. Any merger or acquisition is likely to be financed through a combination of debt and equity.

Outlook

In the first quarter of 2020, the COVID-19 outbreak spread quickly across the globe. Federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, such as stay-at-home orders, closures of restaurants and banning of group gatherings have resulted in a severe drop in general economic activity, as well as a corresponding decrease in global energy demand. Additionally, the risks associated with COVID-19 have impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, we have asked the vast majority of our corporate workforce to work remotely as we begin to plan a process to phase employees to return to the office. Working remotely has not significantly impacted our ability to maintain operations, or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures. In addition, actions by the Organization of Petroleum Exporting Countries and other high oil exporting countries like Russia (“OPEC+”) have negatively impacted crude oil prices. These rapid and unprecedented events have pushed crude oil storage near capacity and driven prices down significantly. These events have been the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil pricing. These conditions may continue to exist in future periods. 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 its continuing impact on the business.

Drilling and other Exploratory and Development Strategies

With our success in the leasing of our targeted prospects, our plan has been to partner with other entities which could include oil and gas companies and/or financial investors. Our goal is to diversify risk and minimize capital exposure to exploration drilling costs. We expect a portion of our exploration costs to be paid by our partners through these transactions, in return for our previous investment in prospect generation and delivery of an identified prospect on acreage we control. Such arrangements are a commonly accepted industry method of proportionately recouping pre-drill cost outlays for seismic, land, and associated interpretation expenses. We cannot assure you, however, that we will be able to enter into any such arrangements on satisfactory terms. In any drilling, we expect that our retained working interest will be adjusted based upon factors such as geologic risk and well cost. Early monetization of a discovered asset or a portion of a discovered asset is an option for the Company as a means to fund development or additional exploration projects as an alternative to potential equity or debt offerings. However, if a reasonable value were not received from the market at the discovery stage, then we may elect to retain (subject to lease terms) the discovery asset undeveloped, until a reasonable offer is received in line with our perceived market value, or we may elect to seek development partners on a promoted basis in order to substantially reduce capital development requirements. We will also evaluate and seek to acquire producing properties that have a strategic relationship to our core area.

Current Operations

In 2016,The Company has been conducting pre-drill operations for the Company completed the technical work on seven sub-salt prospects and has declared theseTau prospect which is anticipated to be drill ready.re-drilled to a total depth of approximately 21,000 feet. The Company estimatesExploration Plan and the cost to drillAPD for this well have been filed with BOEM, the exploration wells on these prospects to be approximately $200 million. The recoverable resource potentialExploration Plan has been approved and the APD is estimated to be more than 800 mmboe (million barrels oil equivalent) on a gross (100% working interest) and unrisked basis. Additional prospects are expected to be advanced to the drill ready stage through new seismic reprocessing and/or additional seismic acquisition. pending approval.

The Company continues to be active in the evaluation of potential mergers and producing property acquisitions that it deems to be attractive opportunities. Any such merger or acquisition is likely to be financed through a combination of debt and equity.

As a result of the extensive reprocessing and mapping of its licensed 3D, seismic data, the Company also developed two shallow depth prospects with drilling depths of approximately 5,000 feet.

On January 8, 2018, the Company signed comprehensive documents related to partnering with Delek Group and Texas South to participate in the drilling of nine currently leased prospects. The initial phase (Phase I) consists of a commitment to drill the Canoe Prospect (VR378) to approximately 5000’ and the Tau Prospect (SS336 and SS351) to approximately 26,000’. The Company will fund 8% of the well costs and retain a 20% working interest that is subject to a .8% Net Profits Interest. GulfSlope is the named operator for the exploratory wells. Delek has the option to participate in 3 subsequent phases of drilling under the same terms. It also has the right to purchase up to 5% of the outstanding shares of GSPE common stock after each drilling phase for a cumulative right to purchase 20% of the shares outstanding. The Company will receive a partial recoupment of sunk costs of $1.1M for each prospect to be drilled.

The CompanyTau Prospect is currently preparinglocated approximately six miles northeast of the extensive documentation required forMahogany Field, discovered in 1993. The Mahogany Field is recognized as the permits to drillfirst commercial discovery below allocthonous salt in the exploratory wellsGulf of Mexico. The Tau Prospect is defined by mapping of 3D seismic reprocessed by RTM methods. Drilling operations on the CanoeTau subsalt prospect commenced in September 2018. The wellbore was designed to test multiple Miocene horizons trapped against a well-defined salt flank, including equivalent reservoir sands discovered and developed at the nearby Mahogany Field. The surface location for Tau Prospectswas located in 305 feet of water. In January 2019, the Tau well experienced an underground control of well event and expectsas a result, an insurance claim was filed with the insurance Underwriters for a net amount of approximately $10.8 million for 100% working interest. The insurance claim was subsequently approved. On May 13, 2019, GulfSlope announced the Tau well was drilled to filea measured depth of 15,254 feet, as compared to the permit applicationsoriginally permitted 29,857 foot measured depth. Producible hydrocarbon zones were not established to that depth, but hydrocarbon shows were encountered. Complex geomechanical conditions required two by-pass wellbores, one sidetrack wellbore, and eight casing strings to reach the depth of 15,254 feet. Equipment limitations prevented further drilling at that time. In addition, the drilling rig had contractual obligations related to another operator. Due to these factors, the Company elected to temporarily plug the well in a manner that would allow for both wells in March 2018. Drilling operations are expected to commence mid-2018, subject to receiptre-entry at a later time. Planning is underway for a re-drill of the required permits to drill.

The Company has contracted with Atlantic Maritime Services LLC, for the use of the Rowan Ralph Coffman jackup drilling rig for these two wells. The rig is currently being mobilized from Trinidad to the U. S. Gulf of Mexico.

GulfSlope estimates that it’s net working interest for these two prospects could hold over 50 mmboe recoverable oil and gas and estimates the net cost to the Company to drill these two wells is approximately $4 million.   

The Company has incurred accumulated losses for the period from inception to December 31, 2017 of approximately $39.7 million, and has a net capital deficiency.  Further losses are anticipated in developing its business.  As a result, there exists substantial doubt about the Company’s ability to continue as a going concern on its report for the year ended September 30, 2017.  As of December 31, 2017, the Company had approximately $0.1 million of cash on hand.  The Company estimates that it will need to raise a minimum of $10 million to meet its obligations and planned expenditures through February 2019. These expenditures include the Company’s drilling costs, lease rentals to the BOEM, general and administrative expenses, and costs associated with seismic acquisition and processing.  The Company 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. The Company plans to finance the Company through best-efforts equity and/or debt financings. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.  Tau prospect.

Significant Accounting Policies

The Company uses the full cost method of accounting for its oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”).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”pool“). Such costs include property acquisition costs, geological and geophysical (“G&G”&G“) costs, carrying charges on non-producing properties, costs of drilling both productive and non-productive wellswells. Overhead costs, which includes employee compensation and overhead chargesbenefits including stock-based compensation, incurred that are directly related to acquisition, exploration and development activities.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). The UOP calculation multiplies the percentage of estimated(“UOP“), whereby capitalized costs are amortized over total proved reserves produced each quarter by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A)(“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 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-monthtwelve month period. The cost center ceiling limits such pooled costs tois defined as the aggregatesum of the present value of(a) estimated future net revenues, attributable to proved crude oil and natural gas reserves discounted at 10%, plus 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 less any associated tax effects.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. Since we currently have no proved reserves, the well costs are charged to expense if the exploratory well is determined to be impaired.

As of December 31, 2017,June 30, 2020, the Company’s oil and gas properties consisted of wells in process, capitalized exploration and acquisition costs for unproved properties and no proved reserves.

Property and equipment are carried at cost. We assess the carrying value of our property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

A more complete discussion ofThere has been no change to our critical accounting policies isas included in our annual report on Form 10-K as of September 30, 2017,2019, which was filed with the Securities and Exchange Commission on December 29, 2017.  30, 2019.

Factors Affecting Comparability of Future Results  

Success in Acquiring Oil and Gas Leases or Prospects.   As a result of our 3-D seismic imaging and reprocessing, we currently hold twelve lease blocks in the U.S. Gulf of Mexico, which we believe may potentially contain economically recoverable reserves. 

We have No Proved Reserves. While we have acquired most of the oil and gas properties that we pursued, we have no proved reserves.  We have identified prospects based on available seismic and geological information that indicate the potential presence of oil or gas, and we own the drilling and production rights for these prospects.  Some of our current prospects may require additional seismic data reprocessing and interpretation.  Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying structures and hydrocarbon indicators and do not enable the interpreter to have certainty as to whether hydrocarbons are, in fact, present in those structures. We do not know if any prospect will contain oil or gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. 

Success in the Discovery and Development of Reserves.   Because we have no operating history in the production of oil and gas, our future results of operations and financial condition will be directly affected by our ability to discover and develop reserves through our drilling activities.

Oil and Gas Revenue.   We have not yet commenced oil and gas production. If and when we do commence production, we expect to generate revenue from such production. No oil and gas revenue is reflected in our historical financial statements.

General and Administrative Expenses.   We expect that our general and administrative expenses will increase in future periods when we commence drilling operations.

Demand and Price.   The demand for oil and gas is susceptible to volatility related to, among other factors, the level of global economic activity and may also fluctuate depending on the performance of specific industries. We expect that a decrease in economic activity, in the United States and elsewhere, would adversely affect demand for any oil and gas we may produce. Since we have not generated revenues, these key factors will only affect us if and when we produce and sell hydrocarbons.

For a more complete discussion of the factors affecting comparability of our future results, see the risk factors included in Item 1A our annual report on Form 10-K as of September 30, 2017, which was filed with the Securities and Exchange Commission on December 29, 2017.   

Three Months Ended December 31, 2017June 30, 2020 Compared to Three Months Ended December 31, 2016June 30, 2019

NoThere was no revenue was recorded during the three months ended December 31, 2017June 30, 2020 and 2016. 2019. We incurred approximately $2.1 million of impairment of oil and natural gas properties for the three months ended June 30, 2020 and $4.3 million for the three months ended June 30, 2019. This is due to the expiration of oil and gas leases for the three months ended June 30, 2020 and 2019. General and administrative expenses were approximately $0.3 million for the three months ended December 31, 2017,June 30, 2020, compared to approximately $0.2$0.4 million for the three months ended December 31, 2016. This increase is primarily due to stock compensation expense. InterestJune 30, 2019. Net interest expense was $0.2approximately $1,100 with interest expense of approximately $1.2 million for the three months ended December 31, 2017June 30, 2020 net of approximately $1,000 of interest income and approximately $1.2 million of interest expense capitalized to unevaluated oil and natural gas properties, as compared to $0.3approximately $1.7 million for the three months ended December 31, 2016.June 30, 2019 with interest expense of approximately $2.1 million for the three months ended June 30, 2019 net of approximately $17,000 of interest income and approximately $0.4 million of interest expense capitalized to unevaluated oil and natural gas properties. Loss on debt extinguishment was approximately $18,000 for the three months ended June 30, 2020 and nil for the three months ended June 30, 2019. This decreasewas primarily due to convertible note and accrued interest conversions in exchange for the issuance of common stock for the three months ended June 30, 2020. Loss on derivative financial instrument was $0.2 million and a $0.1 million for the three months ended June 30, 2020 and 2019, respectively, which was caused by the change in fair value of the underlying derivative financial instruments.

Nine Months Ended June 30, 2020 Compared to Nine Months Ended June 30, 2019

There was no revenue during the nine months ended June 30, 2020 and 2019. We incurred approximately $2.1 million of impairment of oil and natural gas properties for the nine months ended June 30, 2020 and $4.3 million for the nine months ended June 30, 2019. This is due to the reductionexpiration of oil and gas leases for the nine months ended June 30, 2020 and 2019. General and administrative expenses were approximately $1.2 million for the nine months ended June 30, 2020, compared to approximately $1.0 million for the nine months ended June 30, 2019. Interest expense was approximately $16,000 for the nine months ended June 30, 2020, with interest expense of approximately $2.4 million net of interest income of approximately $22,000 and capitalized interest of approximately $2.4 million compared to approximately $1.7 million for the nine months ended June 30, 2019 with interest expense of approximately $2.4 million net of interest income of approximately $65,000 and capitalized interest of approximately $0.6 million. Loss on debt extinguishment was approximately $1.6 million for the nine months ended June 30, 2020 and $5.1 million for the nine months ended June 30, 2019. This was primarily due to convertible note and accrued interest conversions for the nine months ended June 30, 2020, and to loan and subsequent warrant exercise resulting in debt discount amortization.   loan extinguishment for the nine months ended June 30, 2019. Gain on derivative financial instrument was $1.5 million for the nine months ended June 30, 2020 and a loss of approximately $0.1 million for the nine months ended June 30, 2019, which was caused by the change in fair value of the underlying derivative financial instruments.

Liquidity and Capital Resources

The Company has incurred accumulated losses for the period from inception to June 30, 2020, of approximately $59.1 million, and has a negative working capital of $18.4 million. For the nine months ended June 30, 2020, the Company has generated losses of $3.5 million and net cash used in operations of $0.1 million. As of December 31, 2017, we had $0.1June 30, 2020, there was $1.06 million of cash on hand.hand, $0.8 million of this amount is for joint payables from drilling operations. The Company estimates that it will need to raise a minimum of $10 million to meet its obligations and planned expenditures through February 2019.August 2021. The $10 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 as of June 30, 2020. The Company plans to finance its operations and planned expenditures through the issuance of equity andsecurities, debt financings.financings, farm-out agreements, mergers or other transactions to include the cash settlement of the Company’s insurance claim. Our policy has been to periodically raise funds through the sale of equity on a limited basis, to avoid undue dilution while at the early stages of execution of our business plan. Short term needs have been historically funded through loans from executive management. There are no assurances that financing will be available with acceptable terms, if at all. If the Company is not successful in obtaining financing, operations would need to be curtailed or ceased. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty. In July 2020, the Company reached agreement with the Underwriters to accept a settlement in lieu of a re-drill (See Note 12 - Subsequent Events).

For the threenine months ended December 31, 2017,June 30, 2020, the Company used approximately $0.18$0.1 million of net cash infrom operating activities, compared with approximately $0.10$7.0 million of net cash used in operating activities for the threenine months ended December 31, 2016, due to increased general and administrative and professional expenses.June 30, 2019. For the threenine months ended December 31, 2017June 30, 2020, we receivedused approximately $0.1$0.4 million of cash fromin investing activities compared with approximately $0.06$9.1 million of cash used in investing activities for the threenine months ended December 31, 2016 primarily due to a net of $0.1 million fromJune 30, 2019. For the sale of working interest for the threenine months ended December 31, 2017. For the three months ended December 31, 2017June 30, 2020, we received approximately $0.2$0.4 million of net cash from financing activities, compared with approximately $0.2$12.8 million received in financing activities for the threenine months ended December 31, 2016.   June 30, 2019. These amounts are from loan proceeds of approximately $0.5 million received from the issuance of Convertible Debentures and the execution of a PPP loan during the nine months ended June 30, 2020 and $12.8 million of loan proceeds received for the nine months ended June 30, 2019.

We will need to raise additional funds to cover expenditures planned after February 2019,expenditures, as well as any additional, unexpected expenditures that we may encounter. Future equity financings may be dilutive to our stockholders. Alternative forms of future financings may include preferences or rights superior to our common stock. Debt financings may involve a pledge of assets and will rank senior to our common stock. We have historically financed our operations through private equity and debt financings. We do not have any credit or equity facilities available with financial institutions, stockholders or third partythird-party investors, and will continue to rely on best efforts financings. The failure to raise sufficient capital could cause us to cease operations.   operations, or the Company would need to sell assets or consider alternative plans up to and including restructuring.

Off-Balance Sheet Arrangements

None.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Due to the historical volatility of commodity prices, if and when we commence production, our financial condition, results of operations and capital resources will be highly dependent upon the prevailing market prices of oil and natural gas. These commodity prices are likely to continue to be subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. In the future, we may enter into various derivative instruments to manage our exposure to volatility of commodity market prices. We may use options (including floors and collars) and fixed price swaps to mitigate the impact of downward swings in commodity prices to our cash flow. All contracts will be settled with cash and would not require the delivery of physical volumes to satisfy settlement. While in times of higher commodity prices this strategy may result in our having lower net cash inflows than we would otherwise have if we had not utilized these instruments, management believes the risk reduction benefits of such a strategy would outweigh the potential costs.

At December 31, 2017,June 30, 2020, we had approximately $8.9$12.4 million of fixed-rate debt outstanding. All fixed-rate debt has a weighted average interest rate of 5%. We also had approximately $1.1 million of convertible debt with a weighted average interest rate of 7.6%6.2%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in rules and forms adopted by the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the principal executive and principal financial officers, to allow timely decisions regarding required disclosures.

Under the supervision and with the participation of our principal executive and principal financial officers, our management evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our principal executive and principal financial officers concluded that, as of the end of the period covered by this Quarterly Report on Form 10-Q, our disclosure controls and procedures were not effective at a reasonable assurance level to ensure that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

As noted in the Company’s Annual Report on Form 10-K for the year ended September 30, 2019, the design and operating effectiveness of our controls were inadequate to ensure that certain account analysis and accounting judgments related to certain estimates throughout the year were properly accounted for and reviewed in a timely manner.

Limitations on the Effectiveness of Controls

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is designed to provide reasonable assurance as to the reliability of the Company’s financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Changes in Internal Control Over Financial Reporting

DuringManagement is in the fiscal quarter coveredprocess of adding additional resources with expertise in accounting for complex accounting matters, including timely review and is investigating expansion of the accounting department in its ongoing remediation efforts of the material weaknesses reported by thismanagement in our Annual Report on Form 10-K. Other than the ongoing remediation efforts, there hashave been no changechanges in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that hashave materially affected, or isare reasonably likely to materially affect, our internal control over financial reporting.

PART II -– OTHER INFORMATION

Item 1. Legal Proceedings

From time to time, the Company may become involved in litigation relating to claims arising out of its operations in the normal course of business. No legal proceedings, government actions, administrative actions, investigations or claims are currently pending against us or involve the Company.

Item 1A. Risk Factors

There have been no material changes from the risk factors disclosed in Item 1A. Risk Factors of our Annual Report on Form 10-KNot required for the year ended September 30, 2017, which was filed with the Securities and Exchange Commission on December 29, 2017.smaller reporting companies.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the quarter ended December 31, 2017, the Company issued 2,000,000 shares of restricted stock to a lender as part of two financing transactions.None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The following exhibits are attached hereto or are incorporated by reference:

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Issuer has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.   

GULFSLOPE ENERGY, INC.

(Issuer)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Issuer has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

GULFSLOPE ENERGY, INC.

(Issuer)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Issuer has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.

GULFSLOPE ENERGY, INC.

(Issuer)