GULFSLOPE ENERGY, INC. - Quarter Report: 2019 December (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 quarter ended December 31, 2019

Commission File No. 000-51638

GULFSLOPE ENERGY, INC.

(Exact Name of Issuer as Specified in its Charter)

1331 Lamar St., Suite 1665

Houston, Texas 77010

(Address of Principal Executive Offices)

(281) 918-4100

(Issuer’s Telephone Number)

Securities registered pursuant to Section 12(b) of the Act:

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 (the “Exchange Act”) 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 February 13, 2020, was 1,162,564,741.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Report”) contains statements that constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, as amended. All statements other than statements of historical facts included in this Report including, without limitation, statements in the Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report, regarding our financial condition, estimated working capital, business strategy, the plans and objectives of our management for future operations and those statements preceded by, followed by or that otherwise include the words “believe”, “expects”, “anticipates”, “intends”, “estimates”, “projects”, “target”, “goal”, “plans”, “objective”, “should”, or similar expressions or variations on such expressions are forward-looking statements. We can give no assurances that the assumptions upon which the forward-looking statements are based will prove to be correct. Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by the forward-looking statements. There are a number of risks, uncertainties and other important factors that could cause our actual results to differ materially from the forward-looking statements including, but not limited to, economic conditions generally and in the markets in which we may participate, competition within our chosen industry, technological advances and failure by us to successfully develop business relationships. 

Except as otherwise required by the federal securities laws, we disclaim any obligations or undertaking to publicly release any updates or revisions to any forward-looking statement contained in this Report to reflect any change in our expectations with regard thereto or any change in events, conditions or circumstances on which any such statement is based.

PART I – FINANCIAL STATEMENTS (Unaudited)

December 31, 2019

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.

Statements of Stockholders’ Equity (Deficit)

(unaudited)

For the Three Months Ended December 31, 2019

For the Three Months Ended December 31, 2018

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

December 31, 2019

(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 has leased seven federal Outer Continental Shelf blocks (referred to as “prospect,” “portfolio” or “leases”) and licensed three-dimensional (3-D) seismic data in its area of concentration.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

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

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted pursuant to certain rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed financial statements should be read in conjunction with the audited financial statements for the year ended September 30, 2019, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2019, and filed with the Securities and Exchange Commission on December 30, 2019.

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 December 31, 2019 and September 30, 2018.

Liquidity/Going Concern

The Company has incurred accumulated losses as of December 31, 2019 of $55.7 million, has negative working capital of $19.6 million and for the three months ended December 31, 2019 generated losses of $0.2 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, 2019, we had $3.8 million of unrestricted cash on hand, $3.1 million of this amount is for the payment of joint payables from drilling operations. The Company estimates that it will need to raise a minimum of $10.0 million to meet its obligations and planned expenditures through February 2021. 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 $13.3 million of current principal and interest as of December 31, 2019. The Company plans to finance operations and planned expenditures through equity and/or debt financings and/or farm-out agreements. 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 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 December 31, 2019 and 2018, no allowance was recorded. Accounts receivable from oil and gas joint operations and joint ventures is $2.7 million and $8.5 million at December 31, 2019 and 2018, 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 considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions. In countries where proved reserves exist, exploratory drilling costs associated with dry holes are transferred to proved properties immediately upon determination that a well is dry and amortized accordingly. In countries where a reserve base has not yet been established, impairments are charged to earnings.

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

The Company capitalizes exploratory well costs into oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. The well costs are charged to expense if the exploratory well is determined to be impaired. The Company has drilled two well bores and is currently evaluating such wells for proved reserves. Accordingly such costs are included as suspended well costs at December 31, 2019 and it is expected that a final analysis will be completed in the next nine months at which time the costs will be transferred to the full cost pool.

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 has drilled two well bores and is currently evaluating these wells. The two wellbores drilled in 2018 and 2019, were both plugged while the company continues to evaluate well log data and therefore the costs related to the asset retirement obligation were incurred. Such costs were recognized as capitalized oil and gas costs. The asset retirement obligation was completely extinguished in that if the wells prove not to be commercially viable, there is no further cost needed to remediate the site.

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 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, restricted stock and convertible notes payable. The number of potential common shares outstanding relating to stock options, warrants, and restricted stock 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 months ended December 31, 2019 and 2018, the potentially dilutive shares are anti-dilutive and are thus not added into the loss per share calculations. As of December 31, 2019 and 2018, there were 437,801,338 and 223,537,733 potentially dilutive shares, respectively.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU No. 2016-02, “Leases,” and in March 2019, the FASB issued ASU No. 2019-01, “Leases: Codification Improvements”, which updated the accounting guidance related to leases to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. They also clarify implementation issues. These updates are effective for public companies for annual periods beginning after December 15, 2018, including interim periods therein. Accordingly, the standard was adopted by the Company on October 1, 2019. The standard was applied utilizing a modified retrospective approach and is reflected in these financial statements. See Note 10.

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 January 1, 2019 with no material impact to stock compensation issued to non-employees during the three months ended December 31, 2019.

The Company has evaluated all other recent accounting pronouncements and believes that none of them will have a significant effect on the Company’s financial statements.

NOTE 3 – OIL AND NATURAL GAS PROPERTIES

The Company currently has under lease seven 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 shares of the drilling costs to date. GulfSlope drilled the first well, Canoe, to a total depth of 5,765 feet (5,670 feet TVD) and encountered no problems while drilling. The well completed drilling in August 2018 and based on Logging-While-Drilling (LWD) and Isotube analysis of hydrocarbon samples, oil sands were encountered. A full integration of the well information and seismic data is being performed for further evaluation of the shallow potential of the wellbore and the block, and to define commerciality of these oil pays. Multiple open hole plugs were set across several intervals and the well is equipped with a mud-line suspension system for possible future re-entry. A deeper subsalt prospect exists on the Canoe lease block, for which the block was originally leased. Calibration of seismic amplitudes, petrophysical analysis, reservoir engineering and scoping of development is currently underway to determine the commerciality of these sands, and that work is expected to be completed during the second calendar quarter of 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 abandon this well in a manner that would allow for re-entry at a later time. The drilling, pressure, and reservoir information has confirmed geophysical and geological models, and reinforces the Company’s confidence that there is resource potential. The Company is currently evaluating various options related to future operations in this wellbore and testing of the deeper Tau prospect.

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 (the “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 quarter ended December 31, 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 well experienced a second underground control of well event and as a result, the Company filed an insurance claim. The Underwriters have acknowledged confirmation of coverage, subject to the Policy terms and conditions, related to a subsurface well occurrence that happened during the drilling of the Company's Tau 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 will 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 are estimated at approximately $4.8 million (net of deductible) for 100% working interest and approximately $2.6 million has been received as of December 31, 2019. GulfSlope’s share of this amount was approximately $0.6 million.

As of December 31, 2019, the Company’s oil and natural gas properties consisted of unproved properties, wells in process and no proved reserves. During the three months ended December 31, 2019 and 2018, the company capitalized approximately $0.4 million and $0.1 million of interest 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.  

NOTE 4 – RELATED PARTY TRANSACTIONS

During April 2013 through September 2017, the Company entered into convertible promissory notes whereby it borrowed a total of $8,675,500 from John Seitz, the chief executive 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). As of December 31, 2019, the total amount owed to John Seitz is $8,675,500.  This amount is included in loans from related parties within the balance sheet. There was a total of $2,191,739 of unpaid interest associated with these loans included in accrued interest payable within the balance sheet as of December 31, 2019.

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 5).

Domenica Seitz CPA, related to John Seitz, has provided accounting consulting services to the Company. During the three month period ended December 31, 2019 and 2018, the services provided were valued at $14,880, respectively. The amount owed to this related party totals $380,784 and $365,904 at December 31 2019 and September 30, 2019, respectively. The Company has accrued these amounts, and they have been reflected in related party payable in the December 31, 2019 financial statements.

See Note 5 for a description of the Delek term loan replaced by convertible debenture.

NOTE 5 – TERM LOAN AND CONVERTIBLE PROMISSORY NOTES

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 had a maturity of one year (which has been extended to April 30, 2020), 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 at December 31, 2019 and 2018 are $277,000, respectively, with remaining unamortized debt discounts of $56,620 and zero, respectively. Debt discount amortization for the three months ended December 31, 2019 and 2018 was approximately $43,000 and zero, respectively. Accrued interest for the quarter ended December 31, 2019, was approximately $6,000 and cumulative accrued interest was approximately $77,000.

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 security interest in substantially all of 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 has a right to prepay all principal and accrued interest prior to maturity. At December 31, 2019, the accrued interest payable related to this note was approximately $30,000.

The Company accounted for this 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 815, Derivatives and Hedging due to the potential variable conversion feature which lacks an explicit limit on the number of shares that may require upon conversion. Accordingly, the Company valued the embedded conversion feature and host instrument at their fair values of $479,498 and $1,220,548, respectively, and recognized a loss on extinguishment of $676,785. The fair value of the host note was determined by discounting the future cash flows of the note 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 embedded conversion option was $119,647 at December 31, 2019.

The fair value of the embedded conversion feature was determined utilizing a Geometric Brownian Motion Stock Path Based Monte Carlo Simulation that utilized the following 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 convertible debentures (“Convertible Debentures”) and associated warrants. On June 21, 2019, approximately $2,100,000 of Convertible Debentures were purchased with other tranches closing on August 7, 2019 for $400,000 and November 6, 2019 for $500,000. All tranches accrue interest at eight percent per annum, mature on June 21, 2020, 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. Such warrants expire on the fifth anniversary of issuance. In total the offering costs incurred related to this convertible debenture were approximately $398,000 ($65,000 incurred during the three months ended December 31, 2019).

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. In addition, the Company concluded the warrants required treatment as derivative liabilities as the Company could not assert in 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 remeasured to fair value each reporting period. The Company recognized gains of approximately $770,000 and $131,000 for the three months ended December 31, 2019 related to the change in fair value of the embedded conversion feature and warrants, respectively.

In addition, during the three months ended December 31, 2019, the lender converted $300,000 of principal and $83,637 of accrued interest. Given the embedded conversion feature for the debenture is bifurcated for accounting purposes, this represents the issuance of common stock to extinguish two liabilities. The common stock issued was recorded at its fair value on the dates of issuance ($548,391) and a loss on extinguishment of debt was recognized for approximately $279,584.

The fair value of the embedded conversion feature 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 incorporates the variable conversion price which is simulated as 80% of the lowest trading price within the ten consecutive days preceding presumed conversion.

The Company’s convertible promissory notes consisted of the following as of December 31, 2019.

NOTE 6 – 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 December 31, 2019:

Non-recurring fair value assessments include impaired oil and natural gas property assessments and stock-based compensation. During the three months ended December 31, 2019, the Company recorded stock-based compensation expense of $367,841 of which $186,675 was capitalized to oil and gas properties.

NOTE 7 – COMMON STOCK/PAID IN CAPITAL

As discussed in Note 5, the Company issued 17,919,455 common shares with a fair value of $548,391 upon partial conversions of the notes and related accrued interest during the three months ended December 31, 2019. 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. 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.

During the three months ended December 31, 2018, the Company issued approximately 19.3 million shares of common stock and approximately 9.7 million warrants to accredited investors in a private placement. The funds were received in the prior fiscal year and included as a liability because the transaction did not close until the current fiscal year and it was moved to equity during the quarter ended December 31, 2018. Based upon the allocation of proceeds between the common stock and the warrants, approximately $259,000 was allocated to the warrants.

 The fair value of the warrants was determined using the Black Scholes valuation model with the following key assumptions:

NOTE 8 – STOCK-BASED COMPENSATION

During the three months ended December 31, 2019, 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.

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 $367,841 and $393,000 in stock-based compensation expense for the quarters ended December 31, 2019 and 2018, respectively. A portion of these costs, $186,675 and $318,658 were capitalized to unproved properties for the three months ended December 31, 2019 and December 31, 2018, respectively, with the remainder recorded as general and administrative expenses for each respective period.

The following table summarizes the Company’s stock option activity during the three months ended December 31, 2019:

As of December 31, 2019, there was approximately $0.6 million of unrecognized stock-based compensation expense to be recognized over a period of four months.

NOTE 9 – COMMITMENTS AND CONTINGENCIES

The Company reached an agreement with a vendor in August 2018 for the settlement of approximately $1 million in debt. The vendor was paid approximately $0.16 million in cash and 10 million shares of GulfSlope common stock. The agreement contains a provision that upon the sale of the common stock if the original debt is not 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 from the vendor. The agreement was determined to meet the definition of a derivative in accordance with ASC 815. At December 31, 2019 there is a derivative financial instrument liability of approximately $0.6 million.

In November 2019, the Company purchased a directors and officers’ insurance policy for approximately $241,000 and financed approximately $241,000 of the premium by executing a note payable. The balance of the note payable at December 31, 2019, is approximately $201,000.

NOTE 10 – 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 $16,429 cumulative effect of initially adopting ASC 842 as an adjustment to the opening balance of accumulated deficit.

NOTE 11 – SUBSEQUENT EVENTS

Additional insurance proceeds of approximately $0.07 million were received in January 2020 for 100% working interest related to the Tau well incident (see Note 3).

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” 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 in 450 feet or less of water depth. The Company has under lease seven federal Outer Continental Shelf blocks (referred to as “leases” in this report) and licensed 2.2 million acres 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. 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. This reduced royalty applies to three of the Company’s leases.

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 (“E&P”) companies operating in our core area.

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 September 30, 2019, we had $3.8 million of cash on hand, $3.1 million of this amount is for the payment of joint payables from drilling operations. The Company estimates that it will need to raise a minimum of $10.0 million to meet its obligations and planned expenditures through February 2021. The Company plans to finance its operations through the issuance of equity and/or debt financings. 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.

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 seven leases that comprise five 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 2020, 2022 and 2023. 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.

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

The Company has been conducting pre-drill operations for two prospects to include the Tau prospect which is anticipated to be redrilled in 2020. The Company expects that its current claim under the Policy will provide for a replacement well with all costs covered to the depth of 15,254 feet. The Company will continue drilling operations to a total depth of approximately 21,000 feet with incremental costs to be borne by the working interest participants in the well. The Exploration Plan and the APD for this well have been filed with BOEM and are pending approval.

The Company continues to be active in the evaluation of potential mergers and 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.

On January 8, 2018, the Company signed comprehensive documents related to partnering with Delek 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) and the Tau Prospect (SS336 and SS351). The Company commenced drilling operations at the Canoe prospect in August 2018. The well completed drilling in August 2018 and based on Logging-While-Drilling (LWD) and Isotube analysis of hydrocarbon samples, oil sands were encountered in the northwest center of the block. The well was drilled to a total of 5,765 feet measured depth (5,700 feet true vertical depth) and encountered no problems while drilling. A full integration of the well information and seismic data is being performed for further evaluation of the shallow potential of the wellbore and the block, and to define commerciality of these oil pays. The well was temporarily abandoned, and multiple open hole plugs were set across several intervals. The well is equipped with a mud-line suspension system for possible future re-entry. A deeper subsalt prospect on the Canoe lease block, for which the block was originally leased, is drill-ready, due to further seismic enhancement.

The Tau Prospect is located approximately six miles northeast of the Mahogany Field, discovered in 1993. The Mahogany Field is recognized as the first commercial discovery below allocthonous salt in the Gulf of Mexico. The Tau Prospect is defined by mapping of 3D seismic reprocessed by RTM methods. Drilling operations on the Tau subsalt prospect commenced in September 2018. The wellbore is 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 is located in 305 feet of water. In January 2019, the Tau well experienced an underground control of well event and as a result, we filed an insurance claim with its 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 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 the current depth, but hydrocarbon shows were encountered. Complex geomechanical conditions required two by-pass wellbores, one sidetrack wellbore, and eight casing strings to reach the current depth. Equipment limitations prevent further drilling at this time. In addition, the drilling rig had contractual obligations related to another operator. Due to these factors, the Company has elected to temporarily abandon this well in a manner that would allow for re-entry at a later time. The Company is planning for a redrill of theTau prospect in 2020.

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. The Company has drilled two well bores and is currently evaluating such wells for proved reserves. Accordingly, such costs are included as suspended well costs at December 31, 2019 and it is expected that a final analysis will be completed in the next nine months at which time the costs will be transferred to the full cost pool.

As of December 31, 2019, 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, 2019, which was filed with the Securities and Exchange Commission on December 30, 2019.  

Three Months Ended December 31, 2019 Compared to Three Months Ended December 31, 2018

There was no revenue during the three months ended December 31, 2019 and December 31, 2018. General and administrative expenses were approximately $0.5 million for the three months ended December 31, 2019, compared to approximately $0.1 million for the three months ended December 31, 2018. This increase was primarily due to overhead reimbursements from our working interest partners. Interest expense was approximately $0.02 million for the three months ended December 31, 2019 net of approximately $0.4 million of interest expense capitalized to unevaluated oil and natural gas properties, as compared to $0.2 million for the year ended December 31, 2018. Loss on debt extinguishment was approximately $0.9 million for the three months ended December 31, 2019 and nil for the three months ended December 31, 2018. This increase was primarily due to a loan extinguishment and restructure plus accrued interest conversions in exchange for the issuance of common stock for the three months ended December 31, 2019. Gain on derivative financial instrument was $1.2 million and a loss of $0.2 million for the three months ended December 31, 2019 and 2018, respectively, 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 December 31, 2019, of approximately $55.7 million, and has a negative working capital of $19.6 million. For the three months ended December 31, 2019, the Company has generated losses of $0.2 million and net cash flows from operations of $1.8 million. As of December 31, 2019, we had $3.8 million of cash on hand, $3.1 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 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 $13.3 million as of December 31, 2019. The Company plans to finance its operations through the issuance of equity and debt financings. 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 three months ended December 31, 2019, the Company received approximately $1.7 million of net cash from operating activities, compared with approximately $0.4 million of net cash used in operating activities for the three months ended December 31, 2018, due to approximately $5.8 million decrease in receivables offset by a $4.0 million decrease in accounts payable. For the three months ended December 31, 2019, we received approximately $0.6 million of cash from investing activities compared with approximately $1.4 million of cash used in investing activities for the three months ended December 31, 2018, primarily due to a $0.1 million investment in oil and gas properties for the three months ended December 31, 2019 and approximately $1.4 million investment in oil and gas properties for the three months ended December 31, 2018. For the three months ended December 31, 2019 we received approximately $0.4 million of net cash from financing activities, compared with approximately $0.03 million used in financing activities for the three months ended December 31, 2018. This increase is due to debt proceeds received from the purchase of convertible debentures during the three months ended December 31, 2019.

We will need to raise additional funds to cover expenditures planned after February 2020, 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

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, 2019 we had approximately $13.3 million of fixed-rate debt outstanding. All fixed-rate debt has a weighted average interest rate of 6.32%. 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

Management is in the process 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 management in our Annual Report on Form 10-K. Other than the ongoing remediation efforts, there have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are 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

Not required for smaller reporting companies.

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

In December 2019, the Company issued approximately 38.4 million shares of restricted common stock in settlement of a liability.

The offer and sale of the securities described above were made without registration under the Securities Act, and the applicable securities laws of certain states, in reliance upon exemptions provided by Section 4(a)(2) and Regulation D under the Securities Act and in reliance upon similar exemptions under applicable state laws with regard to the offer and sale of securities that are made solely to “accredited investors,” as that term is defined under Rule 501(a) of Regulation D, and do not involve any general solicitation.

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)