GULFSLOPE ENERGY, INC. - Quarter Report: 2021 June (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

☒  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2021

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to ________________

Commission File No. 000-51638

GULFSLOPE ENERGY, INC.
(Exact name of registrant as specified in its charter)

(281) 918-4100
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The number of outstanding shares of the registrant’s common stock, $0.001 par value, on August 13, 2021, was 1,268,240,346.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Report“) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact included in this communication, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast, “may,” “objective,” “plan,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, anticipated impact of the COVID-19 outbreak, and other factors that may affect our future results and business, generally, including those discussed in the Company’s periodic reports that are filed with the SEC and available on the SEC’s website (http://www.sec.gov).

Should one or more of these risks occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, to reflect events or circumstances after the date of this communication.

PART I – FINANCIAL STATEMENTS (Unaudited)

June 30, 2021

CONTENTS

PART I – FINANCIAL STATEMENTS

Item 1. Financial Statements

GulfSlope Energy, Inc.

Condensed Balance Sheets

(Unaudited)

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

GulfSlope Energy, Inc.

Condensed Statements of Operations

(Unaudited)

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

GulfSlope Energy, Inc. 

Condensed Statements of Stockholders’ Equity

(unaudited)

For the Three Months Ended June 30, 2021 

For the Three Months Ended June 30, 2020 

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

GulfSlope Energy, Inc.

Condensed Statements of Stockholders’ Equity

(unaudited)

For the Nine Months Ended June 30, 2021 

For the Nine Months Ended June 30, 2020

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

GulfSlope Energy, Inc.

Condensed Statements of Cash Flows

(Unaudited) 

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

GulfSlope Energy, Inc.

Notes to Condensed Financial Statements

June 30, 2021

(Unaudited)

NOTE 1 – ORGANIZATION AND NATURE OF BUSINESS

GulfSlope Energy, Inc. (the “Company” or “GulfSlope”) is an independent oil and natural gas exploration company whose interests are concentrated in the United States Gulf of Mexico federal waters offshore Louisiana. The Company currently has under lease three federal Outer Continental Shelf blocks (referred to as “prospect,” “portfolio“ or “leases”) and licensed three-dimensional (3-D) seismic data across its area of concentration.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

The condensed financial statements included herein are unaudited. However, these condensed financial statements include all adjustments (consisting of normal recurring adjustments), which, in the opinion of management are necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. The results of operations for interim periods are not necessarily indicative of the results to be expected for an entire year. The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the Company’s condensed financial statements and accompanying notes. Actual results could differ materially from those estimates.

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended September 30, 2020, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2020 and filed with the Securities and Exchange Commission on December 29, 2020.

Cash

GulfSlope considers highly liquid investments with original maturities to the Company of three months or less to be cash equivalents. There were no cash equivalents at June 30, 2021 and September 30, 2020.

Liquidity / Going Concern

The Company has incurred accumulated losses as of June 30, 2021 of $59.7 million, has negative working capital of $12.0 million and for the nine months ended June 30, 2021 generated losses of $1.7 million. Further losses are anticipated in developing our business. As a result, there exists substantial doubt about our ability to continue as a going concern. As of June 30, 2021, we had $1.8 million of unrestricted cash on hand. The Company estimates that it will need to raise a minimum of $10.0 million to meet its obligations and planned expenditures. The $10.0 million is comprised primarily of capital project expenditures as well as general and administrative expenses. It does not include any amounts due under outstanding debt obligations, which amounted to $11.9 million of current principal and accrued interest as of June 30, 2021. The Company plans to finance operations and planned expenditures through the issuance of equity securities, debt financings and farm-out agreements, asset sales or mergers. The Company also plans to extend the agreements associated with all loans, the accrued interest payable on these loans, as well as the Company’s accrued liabilities. There are no assurances that financing will be available with acceptable terms, if at all, or that obligations can be extended. If the Company is not successful in obtaining financing or extending obligations, operations would need to be curtailed or ceased, or the Company would need to sell assets or consider alternative plans up to and including restructuring. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Accounts Receivable

The Company records accounts receivable for the sale of crude oil, NGL, and natural gas production, and joint interest billings to our partners for their share of expenses on joint venture properties for which we are the operator. 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, 2021 and September 30, 2020, there was no allowance for doubtful accounts receivable. Gross accounts receivable was nil and approximately $0.4 million at June 30, 2021 and September 30, 2020, respectively. 

Full Cost Method

The Company uses the full cost method of accounting for its oil and gas exploration and development activities. Under the full cost method of accounting, all costs associated with successful and unsuccessful exploration and development activities are capitalized on a country-by-country basis into a single cost center (“full cost pool”). Such costs include property acquisition costs, geological and geophysical (“G&G”) costs, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells. Overhead costs, which includes employee compensation and benefits including stock-based compensation, incurred that are directly related to acquisition, exploration and development activities are capitalized. Interest expense is capitalized related to unevaluated properties and wells in process during the period in which the Company is incurring costs and expending resources to get the properties ready for their intended purpose. For significant investments in unproved properties and major development projects that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress, interest costs are capitalized. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. 

Proved properties are amortized on a country-by-country basis using the units of production method (“UOP”), whereby capitalized costs are amortized over total proved reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (“DD&A”), estimated future development costs (future costs to access and develop proved reserves), and asset retirement costs, less related salvage value.

The costs of unproved properties and related capitalized costs (such as G&G costs) are withheld from the amortization calculation until such time as they are either developed or abandoned. Unproved properties and properties under development are reviewed for impairment at least quarterly and are determined through an evaluation that considers, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. In countries where a reserve base has not yet been established, impairments are charged to earnings. At June 30, 2021, the Company continues to pursue the development of its unproved properties and is actively finalizing the permitting of the Tau No. 2 well. As such, project economics continue to support cost incurred plus future development therefore no impairment is required at June 30, 2021.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depreciation, depletion and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

The Company capitalizes exploratory well costs into oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. The well costs are charged to expense if the exploratory well is determined to be impaired. Capitalized exploratory well costs remain pending the outcome of exploration activities involving the drilling of the Tau No. 2 well (twin well). Accordingly, these costs are included as suspended well costs at June 30, 2021 and it is expected that a final analysis will be completed upon the drilling of the Tau No. 2 well or within the next twelve months at which time the costs will be transferred to the full cost pool upon final evaluation.

As of June 30, 2021, the Company’s oil and gas properties consisted of unproved properties, wells in process and 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 significantly declined in 2020. Despite a strong recovery of prices in 2021, oil and gas operators have reduced exploration budgets and activity. The Company has evaluated the effect of these factors on its business and notes these factors have caused a delay in the plans for the Company’s 2021 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 for derivative financial instruments requires that the Company record certain embedded features 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. The Company evaluates each warrant and embedded feature to discern whether derivative accounting is required. As of June 30, 2021, the Company accounts for certain warrants and a make whole provision as derivative liabilities.

Prior to November 19, 2020, the Company had a certain note payable which contained a variable conversion feature with no floor, and accordingly, the Company had adopted a sequencing policy in accordance with ASC 815-40-35-12 whereby all stock-based instruments issued after such note payable was issued and prior to it being extinguished were classified as derivative liabilities with the exception of instruments related to share-based compensation issued to employees or directors. Such sequencing policy ceased upon the extinguishment of the note payable on November 19, 2020.

Basic and Dilutive Earnings Per Share

Basic income (loss) per share (“EPS”) is computed by dividing net income (loss) (the numerator) by the weighted average number of common shares outstanding for the period (denominator). Diluted EPS is computed by dividing net income (loss) by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include stock options, warrants, and convertible notes payable. The number of potential common shares outstanding relating to stock options and warrants, is computed using the treasury stock method. The number of potential common shares related to convertible notes payable is determined using the if-converted method.

As the Company has incurred losses for the three and nine months ended June 30, 2021 and 2020, the potentially dilutive shares are anti-dilutive and are thus not added into the loss per share calculations. As of June 30, 2021 and 2020, there were 299,064,844 and 586,722,166 potentially dilutive shares, respectively.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recently Adopted Accounting Pronouncements

In February 2016, the FASB issued ASU No. 2016-02, “Leases”, and in March 2019, the FASB issued ASU No. 2019-01, “Leases: Codification Improvements”, which updated the accounting guidance related to leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. They also clarify implementation issues. These updates are effective for public companies for annual periods beginning after December 15, 2018, including interim periods therein. Accordingly, the standard was adopted by the Company on October 1, 2019. The standard was applied utilizing a modified retrospective approach and is reflected in these financial statements.

In June 2018, the FASB issued ASU 2018-07, Compensation-Stock Compensation (Topic 718), Improvements to Nonemployee Share-based Payments (“ASU 2018-07”). This ASU expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. The amendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company adopted this new standard effective October 1, 2019, with no material impact to stock compensation issued to non-employees.

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.

NOTE 3 – OIL AND NATURAL GAS PROPERTIES

The Company currently has under lease three 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 Gulf of 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. The second well, Tau No 1, 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 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. The Company plans to finance operations and planned expenditures through equity and/or debt financings, farm-out agreements, and/or other transactions.

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. In December 2019, 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 No. 1 well experienced a second underground control of well event and as a result, the Company filed an insurance claim. The claim was related to a subsurface well occurrence that happened during the drilling of the Company’s Tau No. 1 well on May 5, 2019 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 determined to be approximately $4.8 million (net of deductible) for 100% working interest and all of this amount has been received. GulfSlope’s share of this amount was approximately $1.2 million.

On July 27, 2020, the Company entered into a settlement with the Underwriters of the well control events insurance policy for their claims associated with the re-drilling of the Tau No. 1 well. 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 approximately $6.6 million in cash net to its 25% working interest. All of this amount has been received.

As of June 30, 2021, 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, 2021 and 2020, the Company capitalized nil and approximately $1.2 million of interest expense to oil and natural gas properties, respectively, and approximately $0.04 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, 2021 and 2020, the Company capitalized nil and approximately $2.3 million of interest expense to oil and natural gas properties, respectively, and approximately $0.1 million and $0.7 million of general and administrative expenses, capitalized to oil and natural gas properties, respectively.

NOTE 4 – RELATED PARTY TRANSACTIONS 

During April 2013 through September 2017, the Company entered into convertible promissory notes whereby it borrowed a total of approximately $8.7 million from John Seitz, the chief executive officer (“CEO”). The notes are due on demand, bear interest at the rate of 5% per annum, and approximately $5.3 million 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). As of June 30, 2021, the total amount owed to John Seitz is approximately $8.7 million. This amount is included in loans from related parties within the condensed balance sheets. There was approximately $2.9 million of unpaid interest associated with these loans included in accrued interest payable within the balance sheet as of June 30, 2021.

On November 15, 2016, a family member of the CEO entered into a $50,000 convertible promissory note with associated warrants (“Bridge Financing”) under the same terms received by other investors (see Note 6).

Domenica Seitz CPA, related to John Seitz, has provided accounting services to the Company through September 30, 2020, as a consultant and beginning October 2020 as an employee. During the three months ended June 30, 2021 and 2020, the services provided were valued at approximately $19,000 and $15,000, respectively. During the nine months ended June 30, 2021 and 2020, the services provided were valued at approximately $56,000 and $45,000, respectively. 

NOTE 5 – NOTES PAYABLE

The Company’s notes payable consisted of the following as of September 30, 2020 and June 30, 2021.

PPP Loan 

On April 16, 2020, GulfSlope Energy, Inc. 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 was made through Zions Bancorporation, N.A. dba Amegy Bank (the “Lender”). On December 17, 2020, the PPP Loan plus accrued interest of approximately $600 was formally forgiven in full by the U.S. Small Business Administration. The forgiven loan balance and related interest totaling approximately $100,900 was accounted for as a gain on debt extinguishment in the Condensed Statements of Operations for the nine months ended June 30, 2021.

Insurance Note Payable

In November 2019, the Company purchased an insurance policy for approximately $241,000 and financed $220,629 of the premium by executing a note payable at an interest rate of 5.6%. The note was paid in full in October 2020. The balance of the note payable was nil and approximately $21,000 on June 30, 2021 and September 30, 2020, respectively. This note is included in the Notes Payable balance in the Condensed Balance Sheet.

NOTE 6 – CONVERTIBLE NOTES PAYABLE

 The Company’s convertible promissory notes consisted of the following as of September 30, 2020, and June 30, 2021. 

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, including $222,000 from related parties. These notes and associated warrants had a maturity of one year (which has been extended at maturity to April 30, 2022), 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 note balances, as of June 30, 2021 and September 30, 2020, were $277,000, with unamortized debt discounts of approximately $72,000 and $11,000, respectively. Debt discount amortization for the three months ended June 30, 2021 and 2020 was approximately $16,000 and $17,000, respectively. Debt discount amortization for the nine months ended June 30, 2021 and 2020 was approximately $26,000 and $103,000, respectively. In consideration for the extension of the notes, the Company extended the term of the related warrants until April 30, 2022, and recognized approximately $87,000 of additional debt discount which represented the incremental value of the modified warrants over the pre-modification warrants.

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 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 addition, the holder received warrants to purchase an aggregate of 50 million shares of common stock at an exercise price of $0.04 per share (subsequently reduced to an exercise price $0.02 in 2020). Such warrants expire on the fifth anniversary of issuance. In total the offering costs incurred related to this Convertible Debenture were approximately $398,000. 

The Company evaluated the conversion feature and concluded that it should be bifurcated and accounted 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 at issuance and are subsequently re-measured to fair value each reporting period.

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 allocated on a pro-rata basis between Tranche 1 and Tranche 2 and will be amortized using the effective interest method over the remaining life of the respective tranches.

On July 27, 2020, the Company and the holder agreed to the following cash payments in full satisfaction of the obligations thereunder: (1) $50,000 on the date of the Agreement; (2) $700,000 on or before August 21, 2020; (3) $750,000 on or before September 30, 2020; and (4) any remaining principal amount outstanding on or before November 30, 2020. As of the date of the agreement, the principal balance outstanding on the Convertible Debenture was $1,900,000, which amount may be reduced in the event that holder elects to convert to equity all or any portion of principal prior to repayment. In connection with the agreement, the holder agreed not to convert more than $300,000 of principal of the Debenture between the date of the agreement and November 30, 2020. 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. The Company accounted for this arrangement as a modification of the existing debt.  

During the year ended September 30, 2020, the lender converted approximately $1,200,000 of principal of Tranche 1 and approximately $139,000 of accrued interest into common stock. The remaining balance of the convertible debenture at September 30, 2020 was $300,000.

In November 2020, the Company made a $300,000 payment in full to satisfy the remaining balance of the convertible debenture.

The fair value of the embedded conversion feature at September 30, 2020 was determined utilizing a Geometric Brownian Motion Stock Path Based Monte Carlo Simulation that utilized the following key assumptions:

In addition to the fixed exercise price noted above, the model incorporated the variable conversion price which is simulated as 80% of the lowest trading price within the ten consecutive days preceding presumed conversion.

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 September 30, 2020, and June 30, 2021, respectively:

The change in derivative financial instruments for the nine months ended June 30, 2021 is as follows:

Non-recurring fair value assessments include oil and natural gas impairments and stock-based compensation. During the nine months ended June 30, 2021 and 2020, the Company recorded an impairment charge of nil and approximately $2,125,000, and stock-based compensation of approximately $65,000 none of which was capitalized to oil and gas properties and approximately $968,000 of which approximately $498,000 was capitalized to oil and gas properties, respectively.

NOTE 8 – COMMON STOCK/PAID IN CAPITAL

Nine Months Ended June 30, 2021

In October 2020, the Company issued approximately 17.5 million common shares with a fair value of approximately $0.1 million that were reflected on the September 30, 2020 balance sheet as additional paid in capital – shares to be issued. 

Nine Months Ended June 30, 2020

The Company issued approximately 106 million common shares with a fair value of approximately $2.1 million upon partial conversions of the notes and related accrued interest during the nine months ended June 30, 2020. The common shares were valued based upon the closing common share prices on the respective conversion dates.

The Company issued 38,423,221 common shares with a fair value of $1,536,929 to extinguish an accrued expense that totaled $1,613,775 during the nine months ended June 30, 2020. The common shares were valued based upon the closing common share price on the date of settlement resulting in a gain on the extinguishment of the obligation of approximately $77,000.

NOTE 9 – STOCK-BASED COMPENSATION 

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 vesting period. The Company recognized stock-based compensation of approximately $65,000 and $961,000 for the nine months ended June 30, 2021 and 2020, respectively. Of the $65,000 of stock compensation expense for the nine months ended June 30, 2021, all was recorded as general and administrative expense, and of the approximately $961,000 of stock-based compensation recognized for the nine months ended June 30, 2020, approximately $498,000 was capitalized to unproved oil and gas properties, with the remainder recorded as general and administrative expense.

During the nine months ended June 30, 2020, upon the passing of a member of the management team, the Company modified a stock option grant for three million shares made to said management team member in June 2018 to vest such award immediately. The Company recorded approximately $8,000 in additional compensation expense related to this modification. 

The following table summarizes the Company’s stock option activity during the nine months ended June 30, 2021:

As of June 30, 2021, there was approximately $0.06 million of unrecognized stock-based compensation expense.

NOTE 10 – COMMITMENTS AND CONTINGENCIES 

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.

In July 2018, the Company entered into a 39-month lease for approximately 5,000 square feet of office space in 4 Houston Center in downtown Houston. Annual base rent is approximately $94,000 for the first 18 months, increasing to approximately $97,000 and $99,000, respectively, during the remaining term of the lease. The Company accounted for this lease as an operating lease in accordance with ASC 842, Leases. As of June 30, 2021, the right-of-use asset, net related to this lease is approximately $14,000 and the operating lease liability is approximately $24,000. All remaining payments totaling approximately $25,000 are payable within the current fiscal year.

The Company reached an agreement in August 2018 for the settlement of approximately $1 million in debt owed to a third party. As required under the terms of the settlement, the Company made a payment of approximately $0.16 million in cash and 10 million shares of common stock at such time. The agreement also contained a provision such that upon the sale of the common stock by the holder, if the proceeds received were not sufficient to fully satisfy the original debt balance, additional payment by the Company 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 meet the definition of a derivative in accordance with ASC 815. As of June 30, 2021, there is a derivative financial instrument liability recorded of approximately $0.7 million related to this agreement.

NOTE 11 – SUBSEQUENT EVENTS

The Company’s office lease has been extended for 12 months with either party able to cancel by providing a 30-day notice. 

The Company completed a review and analysis of all events that occurred after the condensed balance sheet date to determine if any such events must be reported and has determined that there are no other subsequent events to be disclosed. 

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

Forward-looking Statements

The following discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the notes to those financial statements included in Item 1 of this Quarterly Report on Form 10-Q. The following discussion contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements involve risks, uncertainties and assumptions. If the risks or uncertainties materialize or the assumptions prove incorrect, our results may differ materially from those expressed or implied by such forward-looking statements and assumptions. All statements other than statements of historical fact are statements that could be deemed forward-looking statements, such as those statements that address activities, events or developments that we expect, believe or anticipate will or may occur in the future. These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Known material risks that may affect our financial condition and results of operations are discussed in Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended September 30, 2020, and this Quarterly Report on Form 10-Q, Part II, Item 1A, Risk Factors, and may be discussed or updated from time to time in subsequent reports filed with the Securities and Exchange Commission. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We assume no obligation, nor do we intend to update these forward-looking statements. Unless the context requires otherwise, references in this Quarterly Report on Form 10-Q to “GulfSlope” “we,” “us,” “our” and the “Company” refer to GulfSlope Energy, Inc.

Overview

GulfSlope Energy, Inc. is an independent crude oil and natural gas exploration and production company whose interests are concentrated in the United States Gulf of Mexico federal waters. We are a technically driven company, and we use our licensed 2.2 million acres of advanced three-dimensional (“3-D”) seismic data to identify, evaluate, and acquire assets with attractive economic profiles. GulfSlope Energy commenced commercial operations in March 2013. GulfSlope Energy was originally organized as a Utah corporation in 2004 and became a Delaware corporation in 2012. We have focused our operations on the United States Gulf of Mexico because we believe this area provides us with favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic databases, extensive infrastructure, relatively favorable royalty regime, and an attractive acquisition market and because our management and technical teams have significant experience and technical expertise in this geologic province. Additionally, we licensed 2.2 million acres of advanced 3-D seismic data, a significant portion of which has been enhanced by new, state-of-the-art reprocessing and noise attenuation techniques including reverse time migration depth imaging. We have used our broad regional seismic database and our reprocessing efforts to generate and high-grade oil and natural gas prospects. The use of our extensive seismic database, coupled with our ability, knowledge, and expertise to effectively reprocess this seismic data, allows us to further optimize our drilling operations and to effectively evaluate acquisition and joint venture opportunities. We consistently assess our prospect inventory in order to deploy capital as efficiently as possible. 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 historically operated our business with working capital deficits and these deficits have been funded by equity and debt investments and loans from management. As of June 30, 2021, we had $1.8 million of cash on hand. The Company estimates that it will need to raise a minimum of $10.0 million to meet its obligations and planned expenditures through August 2022. The Company plans to finance operations and planned expenditures through equity and/or debt 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 team has a track record of finding, developing and producing oil and natural gas in various hydrocarbon producing basins including the U. S. Gulf of Mexico. Our team has significant experience in acquiring and operating oil and natural gas producing assets worldwide with particular emphasis on conventional reservoirs. We deployed a technical team with over 150 years of combined industry experience finding 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 locating the images in three dimensions. The Company has invested significant technical person hours in the reprocessing and interpretation of seismic data. 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 companies operating in our core area. 

Industry leading position in our core area. We have licensed 2.2 million acres of 3-D seismic data which covers over 440 Outer Continental Shelf (“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 and petroleum trapping models, gives us an advantage in identifying and high grading drilling and acquisition opportunities in our core area.

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 identify and drill targets below the salt bodies in an area of the shallower waters of the Gulf of Mexico where industry activity has largely been absent for over 20 years. 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 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 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 have been 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 three leases, and we are evaluating the acquisition of additional leases in our core area. Our original leases have a five-year primary term, expiring in 2022, 2023 and 2025. Drilling the Tau No. 2 well will extend the terms of the lease that is set to expire in 2022. 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 Gulf of Mexico, 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 the issuance of debt and/or equity securities. 

Drilling and other Exploratory and Development Strategies

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 of 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.  

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 most 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 our 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+”) negatively impacted crude oil prices in 2020. These rapid and unprecedented events pushed crude oil storage near capacity and drove prices down significantly. These events have been the primary cause of the significant supply-and-demand imbalance for oil, significantly lowering oil pricing in 2020. Despite a strong recovery of prices in 2021, oil and gas operators have reduced exploration budgets and activity. These factors and others have contributed to the volatility of oil and gas prices and may continue to impact prices in future periods. The Company has evaluated the effect of these factors on its business and the Company has determined that these factors could cause a delay in the Company’s 2021 drilling program. The Company continues to monitor the economic environment and evaluate its continuing impact on the business.

President Biden entered office in January 2021 and has made tackling climate change, including the restriction or elimination of future greenhouse gases (“GHGs”), a priority in his administration. The Biden Administration has already adopted several executive orders and is expected to pursue additional orders, legislation, regulations or other regulatory initiatives in support of this agenda. Notably, the Acting Secretary of the U.S. Department of the Interior issued an order on January 20, 2021, effective immediately, that suspends new oil and gas leases and drilling permits on federal lands and offshore waters, including the OCS for a period of 60 days. Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for oil and gas exploration and production on federal lands and offshore waters pending review and reconsideration of federal oil and gas permitting and leasing practices. Subsequent to the issuance of the order issued by the Acting Secretary of Interior, thirteen states brought suit to end the suspension of new oil and gas leases on federal lands and water and to reschedule canceled sales of leases in the Gulf of Mexico, Alaska waters and western states and on June 13, 2021, a federal judge in Louisiana issued a ruling blocking the temporary ban. In response, U.S. Interior Secretary Deb Haaland insisted that Interior is evaluating its options and moving forward on releasing an interim report to guide future leasing decisions. The report is expected to recommend increasing royalty rates among other changes. While these January 20, 2021 and January 27, 2021 orders do not apply to existing leases, the January 27, 2021 order further directs applicable agencies to take measures to eliminate provision of subsidies to the fossil fuel industry, although the term “subsidies” is not defined by the administration. We continue to conduct our operations on our existing leases in the OCS; however, uncertainty on future Biden Administration actions with regards to offshore oil and gas activities on the OCS together with the issuance of any future executive orders or adoption and implementation of laws, rules or initiatives that further restrict, delay or result in cancellation of existing oil and gas activities on the OCS could have a material adverse effect on our business and operations.

Recent Developments

The Company has been conducting pre-drill operations for the Tau prospect which is anticipated to be re-drilled to a total depth of approximately 21,000 feet. The Exploration Plan has been filed with and approved by BOEM and the Application for Permit to Drill (“APD”) has been filed with BSEE and is pending approval. The Company plans to sign a rig contract, and arrange for bonding and insurance in conjunction with the approval of the APD. 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.

Significant Accounting Policies

The Company uses the full cost method of accounting for its oil and gas exploration and development activities. Under the full cost method of accounting, all costs associated with successful and unsuccessful exploration and development activities are capitalized on a country-by-country basis into a single cost center (“full cost pool”). Such costs include property acquisition costs, geological and geophysical (“G&G”) costs, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells. Overhead costs, which includes employee compensation and benefits including stock-based compensation, incurred that are directly related to acquisition, exploration and development activities are capitalized. Interest expense is capitalized related to unevaluated properties and wells in process during the period in which the Company is incurring costs and expending resources to get the properties ready for their intended purpose. For significant investments in unproved properties and major development projects that are not being currently depreciated, depleted, or amortized and on which exploration or development activities are in progress, interest costs are capitalized. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Proved properties are amortized on a country-by-country basis using the units of production method (“UOP”), whereby capitalized costs are amortized over total proved reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion, and amortization (“DD&A”), estimated future development costs (future costs to access and develop proved reserves), and asset retirement costs, less related salvage value.

The costs of unproved properties and related capitalized costs (such as G&G costs) are withheld from the amortization calculation until such time as they are either developed or abandoned. Unproved properties and properties under development are reviewed for impairment at least quarterly and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. In countries where a reserve base has not yet been established, impairments are charged to earnings.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve-month period. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depreciation, depletion and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

The Company capitalizes exploratory well costs into oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. The well costs are charged to expense if the exploratory well is determined to be impaired. Capitalized exploratory well costs remain pending the outcome of exploration activities involving the drilling of the Tau No. 2 well (twin well). Accordingly, these costs are included as suspended well costs as of June 30, 2021, and it is expected that a final analysis will be completed in the next twelve months at which time the costs will be transferred to the full cost pool upon final evaluation.

As of June 30, 2021, 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.

There has been no change to our critical accounting policies as included in our annual report on Form 10-K as of September 30, 2020, which was filed with the Securities and Exchange Commission on December 29, 2020.

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020

There was no revenue during the three months ended June 30, 2021 and 2020. We incurred no impairment of oil and natural gas properties for the three months ended June 30, 2021 and approximately $2.1 million impairment of oil and natural gas properties for the three months ended June 30, 2020. General and administrative expenses were approximately $0.4 million for the three months ended June 30, 2021, compared to approximately $0.3 million for the three months ended June 30, 2020. Net interest expense was approximately $131,000 for the three months ended June 30, 2021, with none capitalized to unevaluated oil and natural gas properties, compared to net interest expense of approximately $1,100 with interest expense of approximately $1.2 million capitalized to unevaluated oil and natural gas properties for the three months ended June 30, 2020, net of approximately $1,000 of interest income. Loss on debt extinguishment was nil for the three months ended June 30, 2021 and approximately $0.02 million for the three months ended June 30, 2020. Gain on derivative financial instruments was approximately $0.1 million for the three months ended June 30, 2021, and for the three months ended June 30, 2020, there was a loss of approximately $0.2 million, respectively.

Nine Months Ended June 30, 2021 Compared to Nine Months Ended June 30, 2020

There was no revenue during the nine months ended June 30, 2021 and 2020. We incurred no impairment of oil and natural gas properties for the nine months ended June 30, 2021, and $2.1 million for the nine months ended June 30, 2020. This is due to the expiration of oil and gas leases for the nine months ended June 30, 2020. General and administrative expenses were approximately $1.1 million for the nine months ended June 30, 2021, compared to approximately $1.2 million for the nine months ended June 30, 2020. This decrease is primarily due to a decrease in professional fees and stock compensation for the nine months ended June 30, 2021. Interest expense was approximately $416,000 for the nine months ended June 30, 2021, with none capitalized to unevaluated oil and natural gas properties and approximately $16,000 for the nine months ended June 30, 2020, with approximately $2.4 million net of interest income of approximately $22,000 capitalized to unevaluated oil and natural gas properties. Gain on debt extinguishment was approximately $0.1 million for the nine months ended June 30, 2021, compared to a loss on debt extinguishment of approximately $1.6 million for the nine months ended June 30, 2020. Loss on derivative financial instrument was approximately $0.3 million for the nine months ended June 30, 2021, compared to gain on derivative financial instrument of approximately $1.5 million for the nine months ended June 30, 2020.

Liquidity and Capital Resources

The Company has incurred accumulated losses for the period from inception to June 30, 2021, of approximately $59.7 million, and has a negative working capital of $12.0 million. For the nine months ended June 30, 2021, the Company has generated losses of approximately $1.7 million and net cash used in operations of approximately $1.2 million. As of June 30, 2021, there was $1.8 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 August 2022. 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 and accrued interest, which amounted to approximately $11.9 million as of June 30, 2021. The Company plans to finance operations and planned expenditures through the issuance of equity securities, debt financings, farm-out agreements, mergers or other transactions. 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.

For the nine months ended June 30, 2021, the Company used approximately $1.2 million of net cash in operating activities, compared with approximately $0.1 million of net cash used by operating activities for the nine months ended June 30, 2020. For the nine months ended June 30, 2021, approximately $0.2 million of cash was provided by investing activities compared with approximately $0.4 million of cash used in investing activities for the nine months ended June 30, 2020. For the nine months ended June 30, 2021, the Company used approximately $0.3 million of cash in financing activities in payment of notes payable, compared with approximately $0.4 million provided by financing activities for the nine months ended June 30, 2020, these amounts are from net loan proceeds of approximately $0.4 million provided by the issuance of Convertible Notes Payable during the nine months ended June 30, 2020.

The Company will need to raise additional funds to cover planned 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-party investors, and will continue to rely on best efforts financings. The failure to raise sufficient capital could cause us to cease 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

Not required for smaller reporting companies.

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 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, 2020, the design and operating effectiveness of our controls were adequate 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

During the fiscal quarter covered by this Report, there has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that has materially affected, or is 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

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risk factors and other cautionary statements described under the heading Part I, Item 1A. “Risk Factors” included in our September 30, 2020 Annual Report, filed with the SEC on December 29, 2020, and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition, or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. Additional risks and uncertainties resulting from recent political and regulatory developments are described below.

The election of President Biden and changes in U.S. Congress may result in significant legislative and regulatory changes that could adversely affect our results of operations, and our ability to implement our business strategy.

President Biden has indicated that his administration will pursue regulatory initiatives, executive actions and legislation in support of his regulatory and political agenda, which includes the reduction in dependence on, and use of, fossil fuels and curtailment of hydraulic fracturing on federal lands in response to climate change and other environmental risks. Our operations in the Gulf of Mexico require permits from federal and state governmental agencies in order to perform drilling and completion activities and conduct other regulated activities. Under certain circumstances, U.S. federal agencies may refuse to approve new leases for hydrocarbon exploration and development on federal lands and waters and may refuse to grant or delay approvals required for development of existing leases on such lands and waters. To the extent that our operations in federal waters are restricted, delayed for varying lengths of time or cancelled, such developments could have a material adverse effect on our results of operations, our ability to replace reserves and the ability to implement our business strategy.

We may be unable to provide the financial assurances in the amounts and under the time periods required by the BOEM to cover our future decommissioning obligations. If in the future the BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, the BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our federal offshore leases.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. The BOEM under the Obama Administration had sought to implement more stringent and costly standards under the existing federal financial assurance requirements through issuance and implementation of NTL #2016-N01, but former President Trump’s Administration first paused, and then in 2020 rescinded, the implementation of this NTL while the BOEM issued a proposed rulemaking in October 2020 to amend its financial assurance program. The BOEM under the Biden Administration may in the future reconsider offshore financial assurance requirements, including the rescinded NTL #2016-N01 and the October 2020 proposed rule, and adopt and implement more stringent requirements. Moreover, the BOEM could make demands for additional financial assurances covering our obligations under our properties, which could exceed the Company’s capabilities to provide. If we fail to comply with such future orders, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

Additional drilling laws, regulations and other restrictions, delays and other offshore-related developments in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

President Biden and one or more of the agencies under his administration has issued orders temporarily suspending leasing or permitting of oil and natural gas activities on federal lands and waters, including the OCS, and his administration is expected to pursue additional orders, legislation and regulatory initiatives regarding deep water leasing, permitting or drilling that could result in more stringent or costly restrictions, delays or cancellations to our operations as well as those of similarly situated offshore energy companies on the OCS. The BSEE and the BOEM have over the past decade, primarily under the Obama Administration, imposed more stringent permitting procedures and regulatory safety and performance requirements with respect to new wells drilled in federal waters. While, in recent years under the Trump Administration, there have been actions by BSEE or BOEM seeking to mitigate or delay certain of those more rigorous standards, we expect that the Biden Administration may reconsider rules and regulatory initiatives implemented under the Trump Administration. Compliance with any added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies under the Biden Administration are expected to continue to evaluate aspects of safety and operational performance in the United States Gulf of Mexico that could result in new, more restrictive requirements. For example, under the Trump Administration, BSEE reviewed and delayed or revised certain offshore regulations implemented during the Obama Administration with respect to the imposition of rigorous standards relating to well control. In light of the statements made by President Biden, there exists a significant risk that these Obama-era regulations, or additional, more stringent regulations impacting our business, properties and results of operations could be reimplemented or adopted during the Biden Administration.

These regulatory actions, or any new rules, regulations, or legal initiatives or controls that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and costs and limit activities in certain areas, or cause us to incur penalties, fines, or result in the suspension or cancellation of leases. Also, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling activities and, in any event, issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

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

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)