GULFSLOPE ENERGY, INC. - Quarter Report: 2018 June (Form 10-Q)

U. S. 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 June 30, 2018

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)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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 shares outstanding of our common stock, as of August 13, 2018, was 817,957,712.

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. A more detailed discussion of possible risks is included in “Risk Factors” included in our Annual Report on Form 10-K filed with the Securities and Exchange Commission on December 29, 2017.

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.

TABLE OF CONTENTS

June 30, 2018

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

GulfSlope Energy, Inc.

Condensed Balance Sheets

As of June 30, 2018 and September 30, 2017

(Unaudited)

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

  GulfSlope Energy, Inc.

Condensed Statements of Operations

For the Three and Nine Months Ended June 30, 2018 and 2017

(Unaudited)

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

GulfSlope Energy, Inc.

Condensed Statement of Stockholder’s Deficit

For the Nine Months Ended June 30, 2018

(Unaudited)

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

GulfSlope Energy, Inc.

Condensed Statements of Cash Flows

For the Nine Months Ended June 30, 2018 and 2017

(Unaudited)

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

GulfSlope Energy, Inc.

Notes to Condensed Financial Statements

June 30, 2018

(Unaudited)

NOTE 1 – ORGANIZATION AND NATURE OF BUSINESS

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

As of June 30, 2018, we have no production or proved reserves.

NOTE 2 – SIGNIFICANT ACCOUNTING POLICIES

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

Certain information, accounting policies, and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been omitted in this Form 10-Q 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, 2017, which were included in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2017 and filed with the Securities and Exchange Commission on December 29, 2017.

Cash

GulfSlope considers highly liquid investments with insignificant interest rate risk and original maturities to the Company of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds.

Liquidity/Going Concern

The Company has incurred accumulated losses as of June 30, 2018 of $41.3 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, 2018, we had $4.9 million of unrestricted cash on hand, $3.2 million of this amount is for the payment of joint payables for drilling operations. The Company estimates that it will need to raise a minimum of $7.5 million to meet its obligations and planned expenditures through August 2019. The Company plans to finance its operations through the issuance of equity and debt offerings. 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 and other related parties. There are no assurances that financing will be available with acceptable terms, if at all. If the Company is not successful in obtaining adequate financing, operations would need to be curtailed or ceased, including those associated with being a public reporting company. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Full Cost Method

The Company uses the full cost method of accounting for its oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). 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 and overhead charges directly related to acquisition, exploration and development activities. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool. Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), 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 ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depreciation, depletion and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

As of June 30, 2018, the Company’s oil and gas properties consisted of wells in process, capitalized exploration and acquisition costs for unproved properties and no proved reserves. 

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, and restricted stock. The number of potential common shares outstanding relating to stock options, warrants, and restricted stock is computed using the treasury stock method.

As the Company has incurred losses for the nine months ended June 30, 2018 and 2017, the potentially dilutive shares are anti-dilutive and are thus not added into the loss per share calculations. As of June 30, 2018 and 2017, there were 214,418,438 and 163,805,888 potentially dilutive shares, respectively.

Recent Accounting Pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). ASU 2014-09 is amended by ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-11, ASU 2016-12, ASU 2016-20, ASU 2017-10, ASU 2017-13 and ASU 2017-14, which FASB issued in August 2015, March 2016, April 2016, May 2016, May 2016, December 2016, May 2017, September 2017 and November 2017, respectively (collectively, the amended ASU 2014-09). The amended ASU 2014-09 provides a single comprehensive model for the recognition of revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. It requires an entity to recognize revenue when the entity transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The amended ASU 2014-09 creates a five-step model that requires entities to exercise judgment when considering the terms of contract(s), which includes (1) identifying the contract(s) with the customer, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations, and (5) recognizing revenue as each performance obligation is satisfied. The amended ASU 2014-09 requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. The effective date for the amended ASU 2014-09 for the Company is fiscal year 2019, including interim reporting periods within that reporting period. Early adoption is permitted for fiscal year 2018, including interim reporting periods within that reporting period. ASU 2014-09 will be effective for us in our first quarter of fiscal 2019. We have evaluated the impact of adoption of this standard and determined that it will not have a material impact on our financial statements. 

On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The new guidance establishes the principles to report transparent and economically neutral information about the assets and liabilities that arise from leases. The new guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted for all organizations. The Company has not yet selected the period during which it will implement this pronouncement, and it is currently evaluating the impact the adoption of ASU 2016-02 will have on its financial statements.  In terms of the Company’s evaluation efforts, the Company has assigned internal resources and engaged third party service providers to assist in its evaluation. We expect this evaluation to be completed by the end of our fiscal year, September 30, 2018.

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

Recent Tax and Financial Legislation

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

NOTE 3 – OIL AND NATURAL GAS PROPERTIES

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

The Company will assign an eight-tenths of one percent of eight/eights net profits interest in certain of the Company’s oil and gas leases to include Vermilion Area, South Addition 378, Ship Shoal Area, South Addition 336, and Ship Shoal Area, South Addition 351, to Hi-View Investment Partners, LLC (“Hi-View”) in consideration for oil and gas consulting services provided pursuant to a non-exclusive consulting engagement dated October 25, 2017, by and between Hi-View, the Company, and Texas South (the “Advisory Agreement”). Hi-View will be entitled to additional assignments on the same terms and conditions as described above related to any of the Leases whereby Delek elects to participate in drilling of an exploratory well. In addition, the Company issued an aggregate of eighty million shares of Common Stock to Hi-View in consideration for oil and gas consulting services provided in facilitating the Delek farm out agreement. The value of the shares was capitalized to unproved properties.

The Company, as the operator of two wells being 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. The first of the two wells was spud in early August 2018 and the second well will be drilled after the first well.

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

In August 2017, the Company entered into a letter agreement with Texas South that sets out the terms of an agreement for the Company’s Tau prospect. In exchange for $166,989, Texas South acquired an undivided 20% interest in the prospect. In accordance with full cost requirements, the Company recorded the proceeds from the transaction as an adjustment to the capitalized costs of its oil and gas properties with no gain or loss recognition.

In October 2017, the Company executed the second amendment to the March 2014 farm-out agreement with Texas South under which Texas South will acquire 20% of Gulfslope’s interest in two prospects for $329,062.

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

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

For the nine months ended June 30, 2018, the Company incurred $180,379 in consulting fees, salaries and benefits associated with geoscientists, $544,958 in stock option costs associated with geoscientists and engineers, $35,125 associated with technological infrastructure and third party hosting services and $90,716 of engineering costs. The Company capitalized these G&G costs to unproved properties. These amounts when added to unproved properties at September 30, 2017 and netted with the receipts of $2,884,651 from the sale of working interests and $140,591 the amount paid for the lease that was acquired in October 2017, the Company’s share of lease rentals of $75,274 paid in May and June of 2018 and the capitalized consulting services of $4,880,000 paid for with the issuance of stock and the wells in process of $384,632 results in unproved properties of $5,334,903 at June 30, 2018. 

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, its current chief executive officer. 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 June 30, 2018 the total amount owed to John Seitz, our CEO, is $8,675,500. There was a total of $1,530,232 of unpaid interest associated with these loans included in accrued interest within our balance sheet as of June 30, 2018.

During March 2016, the Company entered into a promissory note for a total of $80,000 with the Morris Family Partnership, L.P., an affiliate of Mr. Paul Morris, a director of the Company. The $80,000 promissory note was converted into the Bridge Financing (see Note 5). The Bridge note and accrued interest was converted into 3.7 million shares of common stock in June 2018, under the same terms received by other investors. The note was paid in full in June 2018 (see Note 5).

On November 15, 2016, a family member of the CEO, a related party, entered into a $50,000 convertible promissory note with associated warrants (“Bridge Financing”) 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 June 30, 2018, the services provided were valued at $5,915. The Company has accrued these amounts, and they have been reflected in the June 30, 2018 financial statements.

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

NOTE 5 – BRIDGE FINANCING – CONVERTIBLE PROMISSORY NOTES WITH ASSOCIATED WARRANTS

Between June and November 2016, the Company issued eleven convertible promissory notes with associated warrants in a private placement to accredited investors for total gross proceeds of $837,000. Three of the notes were to related parties for proceeds totaling $222,000, including the extinguishment of $70,000 worth of related party payables. The convertible notes have a maturity of one year, bear 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. In addition to the convertible notes, the investors received 27.9 million warrants (7.4 million to the above mentioned related parties) with an exercise price of $0.03 and a term of the earlier of three years or upon a change of control. The Company evaluated the various financial instruments under ASC 480 and ASC 815 and determined no instruments or features required fair value accounting. Therefore, in accordance with ASC 470-20-25-2, the Company allocated the proceeds between the convertible notes and warrants based on their relative fair values. This resulted in an allocation of $452,422 to the warrants and $384,368 to the convertible notes. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible notes to the fair value of the shares they are convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $384,368. Accordingly, the debt discount associated with these notes was $836,790. Such discount was amortized using the effective interest rate method over the term (one year) of the convertible notes. For the quarter ended June 30, 2018 the amortization of this discount and the discount associated with the extension warrants (see below) was zero, because it was fully amortized at March 31, 2018. Accrued interest expense for the quarter ended June 30, 2018 was $14,462.  Cumulative accrued interest at June 30, 2018 was $56,996 after the conversion of three of the notes with a principal balance of $480,000 plus accrued interest of $73,012. The remaining Bridge note balance at June 30, 2018 was $357,000.

Upon maturity of eight of the eleven promissory notes in June 2017, the Company issued 3,225,000 extension warrants (equal to 25% of the original warrant amount) to the holders of the notes to extend the terms to January 15, 2018. The Company evaluated this modification including considering the fair value of the warrants issued and concluded that extinguishment accounting was required as the present value of future cash flows from the new note, including the fair value of the warrants issued to extend, exceeded the present value of future cash flows of the old note by more than 10%. The fair value of the warrants was deemed to be $50,701 and such amount was recognized immediately as a loss on extinguishment of debt. The fair value of the warrants was determined using the Black-Scholes option pricing model.

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

Upon maturity on January 15, 2018 of the eleven promissory notes, the Company issued 2,790,000 extension warrants (equal to 10% of the original warrant amount) to the holders of the notes to extend the term to April 16, 2018. Three of the notes were converted prior to June 30^th and three notes were converted after quarter end. The remaining bridge note holders are working with the Company to extend or convert their notes. The Company evaluated this transaction including considering the fair value of the warrants issued and concluded that extinguishment accounting was required as the present value of future cash flows from the new note, including the fair value of the warrants issued to extend, exceeded the present value of future cash flows of the old note by more than 10%. The fair value of the warrants was deemed to be $217,141 and such amount was recognized immediately as a loss on extinguishment of debt. The fair value of the warrants was determined using the Black-Scholes option pricing model.

On October 16, 2017, the Company issued a convertible promissory note with 1,000,000 shares of restricted stock and 1,100,000 warrants in a private placement to an accredited investor for $100,000 in proceeds. The warrants have a five-year term and an exercise price of $0.10. The promissory note has a face value of $110,000, which includes 10% original issue discount (“OID”), and incurs a one-time upfront interest charge of six percent. The holder of the note has the option to convert the note into shares of common stock at a conversion price of $0.02 per share. Approximately $250,000 of additional funding is available under similar terms if the Company and the lender mutually agree to further tranches. The Company evaluated the various financial instruments under ASC 480 and ASC 815 and determined no material instruments or features required fair value accounting. Therefore, in accordance with ASC 470-20-25-2, the Company allocated the proceeds between the convertible note, restricted common stock, and warrants based on their relative fair values. This resulted in an allocation of $21,287 to the restricted stock, $20,175 to the warrants and $58,538 to the convertible note. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible note to the fair value of the shares it is convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $58,538. Accordingly, at October 16, 2017, the debt discount associated with these notes was $110,000. Such discount will be amortized using the effective interest rate method over the term (seven months) of the convertible note. For the nine months ended June 30, 2018 amortization of this discount totaled $110,000 and is included in interest expense in the statement of operations. Accrued interest expense for the nine months ended June 30, 2018 is $6,600. On April 16, 2018 this note, and accrued interest was paid in full by the issuance of 5.8 million shares of common stock.

On December 15, 2017, the Company issued a convertible promissory note with 1,000,000 shares of restricted stock and 1,100,000 warrants in a private placement to an accredited investor for $100,000 in proceeds. The warrants have a five-year term and an exercise price of $0.10. The promissory note has a face value of $110,000, which includes 10% original issue discount (“OID”), and incurs a one-time upfront interest charge of six percent. The holder of the note has the option to convert the note into shares of common stock at a conversion price of $0.02 per share. Approximately $150,000 of additional funding is available under similar terms if the Company and the lender mutually agree to further tranches. The Company evaluated the various financial instruments under ASC 480 and ASC 815 and determined no material instruments or features required fair value accounting. Therefore, in accordance with ASC 470-20-25-2, the Company allocated the proceeds between the convertible note, restricted common stock, and warrants based on their relative fair values. This resulted in an allocation of $27,807 to the restricted stock, $27,212 to the warrants and $44,981 to the convertible note. After such allocation, the Company evaluated the conversion option to discern whether a beneficial conversion feature existed based upon comparing the effective exercise price of the convertible note to the fair value of the shares it is convertible into. The Company concluded a beneficial conversion feature existed and measured such beneficial conversion feature at $44,981. Accordingly, at December 15, 2017, the debt discount associated with these notes was $110,000. Such discount will be amortized using the effective interest rate method over the term (seven months) of the convertible note. For the nine months ended June 30, 2018 amortization of this discount totaled $110,000 and is included in interest expense in the statement of operations. Accrued interest expense for the nine months June 30, 2018 is $6,600. On June 15, 2018 this note, and accrued interest was paid in full by the issuance of 5.8 million shares of common stock.

NOTE 6 – COMMON STOCK/PAID IN CAPITAL  

At our annual shareholder meeting in May of 2018 our shareholders approved increasing the number of authorized shares of common stock from 975,000,000 to 1,500,000,000. The number of authorized shares of preferred stock was not changed and is 50,000,000.

As discussed in Note 5, between June and November 2016, the Company issued 27.9 million warrants in conjunction with convertible notes payable. The warrants have an exercise price of $0.03 and a term of the earlier of 3 years or upon a change of control. Based upon the allocation of proceeds between the convertible notes payable and the warrants, approximately $452,422 was allocated to the warrants. During June through August 2017, the maturity date of all of the Bridge Financing Notes was extended to January 15, 2018 in exchange for the issuance of 25% additional warrants. The warrants have an exercise price of $0.03 and the same expiration date (three years from original transaction) as the original warrants. On January 15, 2018 the maturity date of the Bridge Financing Notes was extended to April 16, 2018 in exchange for the issuance of 10% additional warrants. (See Note 5 for status of notes). The warrants have an exercise price of $0.10 per share and the same expiration date (three years from original transaction) as the original warrants.

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

(1) Fair market value on the date of agreement.

(2) Average term.

During the period December 2016 through December 2017 the Company issued 3,500,000 shares of restricted stock to an investor as part of financing transactions (see Note 5).

As discussed in Note 5, in December 2016, the Company issued 550,000 warrants in conjunction with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $13,188 was allocated to the warrants. In March 2017, the Company issued 1,100,000 warrants in conjunction with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $14,051 was allocated to the warrants. In October 2017, the Company issued 1,100,000 warrants in conjunction with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $20,175 was allocated to the warrants. In December 2017, the Company issued 1,100,000 warrants in conjunction with a convertible note payable. The warrants have an exercise price of $0.10 and a term of the earlier of 5 years or upon a change of control. Based upon the allocation of proceeds between the convertible note payable and the warrants, approximately $27,212 was allocated to the warrants.

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

NOTE 7 – STOCK-BASED COMPENSATION

On May 1, 2018, 500,000 stock options, with an exercise price of $0.065 per share were granted to an employee. The stock options vested on May 1, 2018. The stock options are exercisable for approximately 7.5 years from the date of grant of May 1, 2018 to December 31, 2025. These stock options were awarded from the Company’s 2014 Omnibus Incentive Plan.

On June 1, 2018, 67.5 million stock options, with an exercise price of $0.075 per share were granted to employees, directors and contractors. 18.5 million of the stock options vested on June 1, 2018, 24 million will vest on June 1, 2019 and 25 million will vest on June 1, 2020 provided the holder continues to serve as an employee or a director on the vesting date. The stock options are exercisable for approximately 7.5 years from the date of grant of June 1, 2018 to December 31, 2025. 49 million of these stock options were awarded from the Company’s 2018 Omnibus Incentive Plan and 18.5 million stock options were inducement awards.

The fair value of the stock-options were determined using the Black Scholes valuation model with the following key assumptions:

The Company used the historical volatility of its stock for the period June 2014 through June 1, 2018 for the Black Scholes computation. The Company has no historical data regarding the expected life of the options and therefore used the simplified method of calculating the expected life. The risk free rate was calculated using the U.S. Treasury constant maturity rates similar to the expected life of the options, as published by the Federal Reserve. The Company has no plans to declare any future dividends.

On January 1, 2017, 33.5 million stock options were granted to 6 employees and 2 directors of the Company. The CEO was not included in the award. The stock options vested 50% on January 1, 2017 and the remaining 50% vested on January 1, 2018, provided that the option holder continues to serve as an employee or director on the vesting date. The stock options are exercisable for seven years from the original grant date of January 1, 2017, until January 1, 2024.

The following table summarizes the Company’s stock option activity during the three months ended June 30, 2018:

The intrinsic value of the options outstanding as of June 30, 2018 was $5.1 million.  As of June 30, 2018 there was $3.1 million of unrecognized stock-based compensation.

Stock-based compensation cost is measured at the grant date, using the estimated fair value of the award, and is recognized over the required vesting period. The Company recognized $1,371,150 and $1,464,534 in stock based compensation during the three and nine months ended June 30, 2018 and $93,381 and $560,287 in stock-based compensation during the three and nine months ended June 30, 2017, respectively. A portion of these costs, $585,858 and $613,733 were capitalized to unproved properties for the three and nine months ended June 30, 2018 and $27,875 and $167,250 was capitalized to unproved properties for the three months and nine months ended June 30, 2017 and the remainder were recorded as general and administrative expenses.  

NOTE 8 – COMMITMENTS AND CONTINGENCIES

In March 2013, the Company licensed certain seismic data pursuant to an agreement for $4,012,260. As of June 30, 2018, the Company has paid $3,109,195 in cash and is obligated to pay $903,065 during 2018.

In October 2017, the Company purchased a directors and officers’ insurance policy for $171,360 and financed $156,718 of the premium by executing a note payable. The balance of the note payable at June 30, 2018 is $43,526.

In June 2018, the Company entered into a thirty-nine month office lease agreement effective July 1, 2018.  In addition, the Company paid a $24,785 security deposit in June 2018.

The Company signed a contract with Atlantic Maritime Services, LLC, a sub subsidiary of Rowan Companies plc, for the use of the Ralph Coffman drilling rig for its joint operations in the Gulf of Mexico. The company’s share of the cost of the drilling rig is approximately $1.1 million. As of June 30, 2018 $0.08 million of this amount has been paid.

NOTE 9 – SUBSEQUENT EVENTS

In the fourth quarter of fiscal 2018, three investors converted their June 2016 bridge notes and accrued interest into approximately 3.7 million shares of common stock in accordance with the terms of the loan documents. These three June 2016 notes and accrued interest have been paid in full.

In the fourth quarter of fiscal 2018, 416,666 warrants were exercised by a Bridge note investor.

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 company whose interests are concentrated in the United States, Gulf of Mexico federal waters offshore Louisiana.  The Company has leased twelve federal Outer Continental Shelf blocks (referred to as “leases” in this report) and licensed 2.2 million acres (440 blocks) of three-dimensional (3-D) seismic data in its area of concentration.

Since March 2013, we have been singularly focused on identifying high-potential oil and gas prospects located on the shelf in the U.S. GOM. We have licensed 3-D seismic data covering approximately 2.2 million acres and have evaluated this 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. We currently hold one lease to which this reduced rate applies. We have filed two exploration plans with BOEM and the first well was spud in early August, with the second well to be drilled thereafter.

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 focus area. We have under lease nine prospects that are covered by our data and throughout this Report we refer to these acquired leases as our “portfolio.”

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

Through June 30, 2018, we have spent approximately $27.3 million on the acquisition, reprocessing, and interpretation of seismic data associated with our seismic license agreements and these costs were capitalized as oil and gas exploration costs which are subject to periodic evaluation for impairment. Approximately $19.5 million of these seismic-related expenses were impaired for accounting purposes. Approximately $7.8 million of our exploration expenditures remain capitalized. These capitalized exploration costs when added with our lease acquisition and annual lease rental costs of $15.3 million and netted with the $13.5 million received from the sale of working interests and the impairment of relinquished leases of $4.7 million, and then added to the amount of our wells in process of $0.4 million results in the $5.3 million reflected as Unproved Oil and Natural Gas Properties on our Condensed Balance Sheet as of June 30, 2018. 

We have historically operated our business with working capital deficits and these deficits have historically been funded by equity investments and loans from management. As of June 30, 2018, we had $4.9 million of cash on hand. The Company estimates that it will need to raise a minimum of $7.5 million to meet its obligations and planned expenditures through August of 2019.  The Company plans to finance its operations through the issuance of equity and debt financings. There are no assurances that financing will be available with acceptable terms, if at all.

Current Operations

The Company has completed the technical work on eight sub-salt prospects and has deemed these to be drill ready. As a result of the extensive reprocessing and mapping of its licensed 3D seismic data, the Company also developed a shallow depth prospect with drilling depths of approximately 6,200 feet. The Company estimates the cost to drill the exploration wells on these prospects to be approximately $235 million. 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 Group and Texas South to participate in the drilling of nine currently leased prospects. The initial phase (Phase I) consists of a commitment to drill the Canoe Prospect (VR378) and the Tau Prospect (SS336 and SS351). The Company will fund 8% of the well costs and retain a 20% working interest that is subject to a 0.8% Net Profits Interest. GulfSlope is the named operator for the exploratory wells. Delek has the option to participate in three subsequent phases of drilling under the same terms. It also has the right to purchase up to 5% of the outstanding shares of GSPE common stock after each drilling phase for a cumulative right to purchase 20% of the shares outstanding. The Company will receive a partial recoupment of sunk costs of $1.1 million for each prospect to be drilled.

The Company has filed and received approval from BOEM for the exploration plans to drill exploratory wells on the Canoe and Tau Prospects. Drilling operations commenced at the Canoe prospect in early August 2018. The Company has contracted with Rowan Companies plc, for the use of the Ralph Coffman jackup drilling rig for drilling these two wells.

The Canoe well targets multiple anomalous amplitudes mapped from 3D seismic that correlate to productive reservoirs in nearby producing fields. The surface location is in 325 feet of water with a proposed measured depth of 6,249 feet.

The Tau Prospect is located approximately six miles northeast of the Mahogany Field, discovered in 1993. 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. The wellbore is planned to drill through approximately 10,000 feet of salt with a deviated well path designed to test multiple horizons trapped against salt. The prospective zones for hydrocarbon accumulations are targeted over a 12,000 foot interval in the Upper and Middle Micocene below salt. In 1994 an offset well two miles to the west of the Tau location penetrated four of these horizons off structure. The surface location for Tau is located in 305 feet of water with a proposed measured depth of 29,728 feet.

The company has completed the shallow hazard seismic survey for a third planned well and has begun the detailed engineering and permitting process for the drilling of that well.

The Company has incurred accumulated losses for the period from inception to June 30, 2018 of approximately $41.3 million, and has a net capital deficiency.  Further losses are anticipated in developing its business.  As a result, there exists substantial doubt about the Company’s ability to continue as a going concern on its report for the year ended September 30, 2017.  As of June 30, 2018, the Company had approximately $4.9 million of cash on hand, $3.2 million of this amount is for the payment of joint payables for drilling operations. The Company estimates that it will need to raise a minimum of $7.5 million to meet its obligations and planned expenditures through August 2019. These expenditures include the Company’s drilling costs, lease rentals to the BOEM, general and administrative expenses, and costs associated with seismic acquisition and processing.  The Company plans to extend the agreements associated with loans from related parties, the accrued interest payable on these loans, as well as the Company’s accrued liabilities. The Company plans to finance the Company through best-efforts equity and/or debt financings. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.  

Significant Accounting Policies

The Company uses the full cost method of accounting for its oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). 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 and overhead charges directly related to acquisition, exploration and development activities. Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Proved properties are amortized on a country-by-country basis using the units of production method (UOP). The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of those reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), 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 ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depreciation, depletion and amortization rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.

 As of June 30, 2018, the Company’s oil and gas properties consisted of wells in process, capitalized exploration and acquisition costs for unproved properties and no proved reserves.   

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

A more complete discussion of our critical accounting policies is included in our annual report on Form 10-K as of September 30, 2017, which was filed with the Securities and Exchange Commission on December 29, 2017.  

Factors Affecting Comparability of Future Results  

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

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

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

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

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

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

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

Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017   

There was no revenue during the three months ended June 30, 2018 and June 30, 2017. General and administrative expenses were approximately $0.8 million for the three months ended June 30, 2018, compared to approximately $0.1 million for the three months ended June 30, 2017. This increase is primarily due to an increase in stock compensation expense for June 30, 2018. Interest expense was $0.2 million for the three months ended June 30, 2018 compared to $0.4 million for the three months ended June 30, 2017, primarily due to differences in debt discount amortization. Loss on debt extinguishment was zero for the three months ended June 30, 2018 compared to $0.05 million for the three months ended June 30, 2017.

Nine Months Ended June 30, 2018 Compared to Nine Months Ended June 30, 2017

There was no revenue during the nine months ended June 30, 2018 and June 30, 2017. General and administrative expenses were approximately $1.2 million for the nine months ended June 30, 2018, compared to approximately $0.7 million for the nine months ended June 30, 2017. This increase of $0.5 million was primarily due to an increase in stock compensation expense of approximately $0.5 million. Interest expense was $0.7 million for the nine months ended June 30, 2018 compared to $1.1 million for the nine months ended June 30, 2017. Loss on debt extinguishment was approximately $0.2 million for the nine months ended June 30, 2018 compared to $0.05 million for the nine months ended June 30, 2017. This increase is due to a debt extension transaction that was treated as a debt extinguishment.

 Liquidity and Capital Resources   

As of June 30, 2018, we had $4.9 million of cash on hand. $3.2 million of this amount is for the payment of joint payables for drilling operations. The Company estimates that it will need to raise a minimum of $7.5 million to meet its obligations and planned expenditures through August 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 financial statements do not include any adjustments that might result from the outcome of this uncertainty.   

For the nine months ended June 30, 2018, the Company received approximately $2.7 million of net cash in operating activities, compared with approximately $0.2 million of net cash used in operating activities for the nine months ended June 30, 2017, due to approximately $3.0 million increase in deposits from joint interest owners offset by a $0.6 million increase in accounts receivable. For the nine months ended June 30, 2018 we received approximately $2.1 million of cash from investing activities compared with approximately $0.4 million of cash used in investing activities for the nine months ended June 30, 2017 primarily due to a net of $2.1 million received from the sale of working interests and investment in oil and gas properties for the nine months ended June 30, 2018, compared to approximately $0.4 million investment in oil and gas properties for the nine months ended in June 30, 2017. For the nine months ended June 30, 2018 we received approximately $0.1 million of net cash from financing activities, compared with approximately $0.5 million received in financing activities for the nine months ended June 30, 2017.  This difference is primarily due to $0.2 proceeds from convertible promissory notes received for the nine months ended June 30, 2018 compared to  $0.7 proceeds from related party and convertible promissory notes received for the nine months ended June 30, 2017.

We will need to raise additional funds to cover expenditures planned after August 2019, 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.   

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 June 30, 2018, we had approximately $8.9 million of fixed-rate debt outstanding. All fixed-rate debt has a weighted average interest rate of 5.0%. We also had approximately $0.4 million of convertible debt with a weighted average interest rate of 8%. 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 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.

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

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

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

During the quarter ended June 30, 2018, the Company issued 1.2 million shares of restricted stock to two consultants and a vendor in settlement of their respective payables.

During the quarter ended June 30, 2018, the Company issued 11.7 million shares of restricted stock to a lender upon lender’s conversion of two convertible notes and all accrued interest.

During the quarter ended June 30, 2018, the Company issued 22.1 million shares of restricted stock to Bridge note holders upon their conversion of three Bridge notes and all accrued interest.

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)