GULFSLOPE ENERGY, INC. - Annual Report: 2021 (Form 10-K)

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended: September 30, 2021

or

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

For the transition period from ___ to ___

Commission File No. 000-51638

GULFSLOPE ENERGY, INC.

(Exact name of the issuer as specified in its charter)

1331 Lamar St., Suite 1665 

Houston, Texas 77010 

(Address of Principal Executive Offices)

(281) 918-4100 

(Registrant’s Telephone Number)

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

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

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐ No☒

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

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

The aggregate market value of the voting stock held by non-affiliates was $11,916,797 based on 768,824,959 shares held by non-affiliates. These computations are based upon the closing sales price of $0.0155 for the common stock of the Company on the OTCPK of the Financial Industry Regulatory Authority, Inc. (“FINRA”) on March 31, 2021.

Indicate the number of shares outstanding of each of the Registrant’s classes of common equity, as of the latest practicable date:

Documents incorporated by reference: None 

TABLE OF CONTENTS

PART I

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

In this Annual Report, references to “GulfSlope Energy,” “GulfSlope,” the “Company,” “we,” “us,” and “our” refer to GulfSlope Energy, Inc., the Registrant.

This Annual Report on Form 10-K (this “Annual Report” or this “Report”) contains certain forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included in this Annual Report are forward looking statements, including, without limitation, statements regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management. These forward-looking statements may be, but are not always, identified by their use of terms and phrases such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “project,” “plan,” “will,” “shall,” “should,” “could” and “potential,” and similar terms and phrases, including when used in the negative. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Actual results could differ materially from those anticipated in these forward-looking statements. All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Annual Report including in Part I, Item 1A, “Risk Factors.” Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

ITEM 1. BUSINESS

General

GulfSlope Energy, Inc. is an independent crude oil and natural gas exploration and production company whose interests are concentrated in the United States Gulf of Mexico federal waters. We are a technically driven company, and we use our licensed 2.2 million acres of advanced three-dimensional (3-D) seismic data to identify, evaluate, and acquire assets with attractive economic profiles. GulfSlope Energy commenced commercial operations in March 2013. GulfSlope Energy was originally organized as a Utah corporation in 2004 and became a Delaware corporation in 2012.

We have focused our operations in the Gulf of Mexico because we believe this area provides us with favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic databases, extensive infrastructure, relatively favorable royalty regime, and an attractive acquisition market and because our management and technical teams have significant experience and technical expertise in this geologic province. Additionally, we licensed 2.2 million acres of advanced 3-D seismic data, a significant portion of which has been enhanced by new, state-of-the-art reprocessing and noise attenuation techniques including reverse time migration depth imaging. We have used our broad regional seismic database and our reprocessing efforts to generate and high-grade oil and natural gas prospects. The use of our extensive seismic database, coupled with our ability, knowledge, and expertise to effectively reprocess this seismic data, allows us to further optimize our drilling operations and to effectively evaluate acquisition and joint venture opportunities. We consistently assess our prospect inventory in order to deploy capital as efficiently as possible. We have given preference to areas with water depths of 450 feet or less where production infrastructure already exists, which will allow for any discoveries to be developed rapidly and cost effectively with the goal to reduce economic risk while increasing returns.

Competitive Advantages

Experienced management. Our management team has a track record of finding, developing and producing oil and natural gas in various hydrocarbon producing basins including the U. S. Gulf of Mexico. Our team has significant experience in acquiring and operating oil and natural gas producing assets worldwide with particular emphasis on conventional reservoirs. We deployed a technical team with over 150 years of combined industry experience finding and developing oil and natural gas in the development and execution of our technical strategy. We believe the application of advanced geophysical techniques on a specific geographic area with unique geologic features such as conventional reservoirs whose trapping configurations have been obscured by overlying salt layers provides us with a competitive advantage.

Advanced seismic image processing. Commercial improvements in 3-D seismic data imaging and the development of advanced processing algorithms, including pre-stack depth, beam, and reverse time migration have allowed the industry to better distinguish hydrocarbon traps and identify previously unknown prospects. Specifically, advanced processing techniques improve the definition of the seismic data from a scale of time to a scale of depth, thus locating the images in three dimensions. The Company has invested significant technical person hours in the reprocessing and interpretation of seismic data. We believe the proprietary reprocessing and interpretation and the contiguous nature of our licensed 3-D seismic data gives us an advantage over other exploration and production companies operating in our core area.

Industry leading position in our core area. We have licensed 2.2 million acres of 3-D seismic data which covers over 440 Outer Continental Shelf (“OCS”) Federal lease blocks on the highly prolific Louisiana outer shelf, offshore Gulf of Mexico. We believe the proprietary and state-of-the-art reprocessing of our licensed 3-D seismic data, along with our proprietary and leading-edge geologic depositional and petroleum trapping models, gives us an advantage in identifying and high grading drilling and acquisition opportunities in our core area.

Technical Strategy

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

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

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

Lease and Acquisition Strategy

Our prospect identification and analytical strategy is based on a thorough understanding of the geologic trends within our core area. Exploration efforts have been focused in areas where lease acquisition opportunities 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 two leases and we are evaluating the acquisition of additional leases in our core area. Our leases have a five-year primary term and are expiring on June 30, 2022 and October 31, 2025, respectively. BOEM’s regulatory framework provides multiple options for leaseholders to apply to receive extensions of lease terms under specified conditions. GulfSlope is exploring all options contained in BOEM’s regulatory framework to extend the terms of the leases. Additional prospective acreage can be obtained through lease sales, farm-in, or purchase. As is consistent with a prudent and successful exploration approach, we believe that additional seismic licensing, acquisition, processing, and/or interpretation may become highly advantageous, in order to more precisely define the most optimal drillable location(s), particularly for development of discoveries.

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

Drilling and Other Exploratory and Development Strategies

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

Oil and Natural Gas Industry

The oil and natural gas industry is a complex, multi-disciplinary sector that varies greatly across geographies. As a heavily regulated industry, operating conditions are subject to political regimes and changing legislation. Governments can either induce or deter investment in exploration and production, depending on legal requirements, fiscal and royalty structures and regulation. Beyond political considerations, exploration and production for hydrocarbons is an extremely risky business with multiple failure modes. Exploration and production wells require substantial investment and are long-term projects, sometimes exceeding twenty years. Regardless of the effort spent on an exploration or production prospect, success is difficult to attain. Even though modern equipment, including seismic equipment and advanced software has helped geologists find producing structures and map reservoirs, they do not guarantee any outcome. Drilling is the only method to ultimately determine whether a prospect will be productive, and even then, many complications can arise during drilling (e.g., those relating to drilling depths, pressure, porosity, weather conditions, permeability of the formation and rock hardness, among others).

Typically, there is a significant chance that exploratory wells will result in non-producing dry holes, leaving investors with the cost of seismic data and a dry well, which can total millions of dollars. Even if oil or gas is produced from a particular well, there is always the possibility that treatment, at additional cost, may be required to make production commercially viable. Further, production profiles decline over time. In summary, oil and gas exploration and production is an industry with high risks and high entry barriers.

Oil and natural gas prices can have a significant impact on the commercial feasibility of a project. Certain projects may become feasible with higher prices or, conversely, may falter with lower prices. Volatility in the price of oil, natural gas and other commodities has increased and is likely to continue in the future. This volatility complicates the assessment of the commercial viability of many oil and gas projects. Most governments have enforced strict regulations to uphold high standards of environmental awareness; thus, holding companies to a high degree of responsibility vis-a-vis protecting the environment. At this time, the Company does not have any production or proved oil or natural gas reserves.

Competition

We operate in a highly competitive environment for generating, evaluating and drilling prospects and for acquiring properties. Many of our competitors are major or large independent oil and natural gas companies that possess and employ financial resources well in excess of the Company’s resources. We believe that we may have to compete with other companies when acquiring leases or oil and gas properties. These additional resources can be particularly important in reviewing prospects and purchasing properties. Competitors may be able to evaluate and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for properties and prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future growth may be diminished or restricted. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drill attempts, delays, sustained periods of volatility in financial or commodity markets and generally adverse global and industry-wide economic conditions and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our operations.

Governmental Regulation

Our oil and natural gas operations are subject to various federal, state, and local governmental regulations. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, pooling of properties, occupational health and safety, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity in order to conserve supplies of oil and natural gas. The production, handling, storage, transportation, and disposal of oil and gas, by-products thereof, and other substances and materials produced or used in connection with oil and gas operations are also subject to regulation under federal, state, and local laws and regulations relating primarily to the protection of human health and the environment. State and local laws and regulations may affect the prices at which royalty owners are paid for their leases by requiring more stringent disclosure and certification requirements, adjusting interest rates for late payments, raising legal and administrative costs and imposing more costly default contractual terms. The requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar business models.

 Our operations on federal oil and natural gas leases in the United States Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”), the Bureau of Ocean Energy Management (“BOEM”) and the Office of Natural Resources Revenue (“ONRR”), which are all agencies of the U.S. Department of the Interior (“DOI”). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the federal Outer Continental Shelf Lands Acts (“OCSLA”). These laws and regulations are subject to change, and many new requirements, including those related to safety, permitting and performance, have been imposed by BSEE and BOEM subsequent to the 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment (“P&A”) of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.

The trend in the United States over the past decade has been for these governmental agencies to continue to evaluate and as necessary develop and implement new, more restrictive requirements, although in recent years under the Trump Administration there have been actions seeking to mitigate certain of those more rigorous standards. For example, in 2016, BSEE under the Obama Administration published a final rule on well control that, among other things, imposed rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of deepwater, high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that on May 15, 2019, BSEE published final revisions to the existing 2016 rule on well control that became effective on July 15, 2019, and among other things, eliminated the requirement for a BSEE-approved verification organization for third parties providing certifications of certain critical well control functions. In another example, BSEE published a final rule in September 2018 amending its production safety systems regulations, which includes the imposition of operational and design standards and the removal of the requirement of offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions. There exists the possibility that certain of these recent mitigatory actions under the Trump Administration could be withdrawn or revised in the future as a result of litigation or by a different presidential administration to impose or re-implement more stringent standards. We expect that the Biden Administration may reconsider rules and regulatory initiatives implemented under the Trump Administration. Compliance with any added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies under the Biden Administration are expected to continue to evaluate aspects of safety and operational performance in the United States Gulf of Mexico that could result in new, more restrictive requirements.

Compliance with these regulatory actions, or any new laws, regulations or other legal initiatives could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. In addition, under certain circumstances, BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect our financial condition and operations.

Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from past hurricanes have included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEM and the BSEE continue to be concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEM and the BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. 

Environmental Regulation

The operation of our future oil and natural gas properties will be subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Applicable U.S. federal environmental laws include, but are not limited to, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the Clean Water Act (“CWA”) and the Clean Air Act (“CAA”). These laws and regulations govern environmental cleanup standards, require permits for air, water, underground injection, waste disposal and set environmental compliance criteria. In addition, state and local laws and regulations set forth specific standards for drilling wells, the maintenance of bonding requirements in order to drill or operate wells, the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the prevention and cleanup of pollutants and other matters. Typically, operators maintain insurance against costs of clean-up operations, but are not fully insured against all such risks. Additionally, U.S. Congress and federal and state agencies frequently revise the environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. There can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief. Accidental releases or spills may occur in the course of the operations of our properties, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

Among the environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry, and our business are the following:

Waste Discharges. The CWA and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants,  including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements of federal laws mandate preparation of detailed plans that address spill response, including appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. 

Air Emissions —The CAA and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants, and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Climate Change — Climate change continues to attract considerable public, political and scientific attention. As a result, numerous regulatory initiatives have been made, and are likely to continue to be made, at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases (“GHG”) as well as to restrict or eliminate such future emissions. These regulatory efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated with the production of fossil fuels and emission of GHGs. The adoption and implementation of any federal or state legislation, regulations or executive orders or the occurrence of any litigation or financial developments that impose more stringent requirements or bans on GHG-emitting production activities or locations where such production activities may occur, impose liabilities for past conduct relating to GHG-emitting production activities, or limit or eliminate sources of financing for on-going production operations could require us to incur increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by OPA. OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. 

National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the U.S. Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments, which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system, by process participants. This process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of existing leases.

Worker Safety. The Occupational Safety and Health Act (“OSH Act”) and comparable state statutes regulate the protection of the health and safety of workers. The OSH Act’s hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSH Act standards regulate specific worker safety aspects of our operations. Failure to comply with OSH Act requirements can lead to the imposition of penalties.

Safe Drinking Water Act. The Safe Drinking Water Act and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance.

Offshore Drilling. In 2011, the U.S. Department of Interior issued new rules designed to improve drilling and workplace safety in the U.S. Gulf of Mexico, and various congressional committees began pursuing legislation to regulate drilling activities and increase liability. The BOEM, BSEE and Office of National Resources Revenue are expected to continue to issue new safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico, and other regulatory agencies could potentially issue new safety and environmental guidelines or regulations in other geographic regions, and may take other steps that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. We are monitoring legislation and regulatory developments; however, it is difficult to predict the ultimate impact of any new guidelines, regulations or legislation. A prolonged suspension of drilling activity or permitting delays in the U.S. Gulf of Mexico and new regulations and increased liability for companies operating in this sector, whether or not caused by a new incident in the region, could adversely affect the business and planned operations of oil and gas companies.

Hazardous Substances and Wastes. CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file corresponding common law claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Protected and Endangered Species. The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act (“MBTA”) implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit. The Marine Mammal Protection Act (“MMPA”) similarly prohibits the taking of marine mammals without authorization. Additionally, the U.S. Fish and Wildlife Service (“FWS”) may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and MMPA are known to exist and where other species that could potentially be protected under these statutes are known to exist. The FWS or the National Marine Fisheries Service may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas. 

Employees

We currently have seven employees. We utilize consultants and contractors, as needed, to perform strategic, technical, operational and administrative functions, and as advisors.

Additional Information

We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, other reports and amendments to those reports with the U.S. Securities and Exchange Commission (“SEC”). Our reports filed with the SEC are available free of charge to the general public through our website at www.gulfslope.com. These reports are accessible on our website as soon as reasonably practicable after being filed with, or furnished to, the SEC. This Form 10-K and our other filings can also be obtained through the SEC’s web site at www.sec.gov. Information on our website is not a part of this Form 10-K. 

ITEM 1A. RISK FACTORS

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report on Form 10-K, including our financial statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

Risks Related to Our Business and Financial Condition

Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms, if at all, in the future, which may in turn limit our ability to execute our business strategy.

We expect our capital outlays and operating expenditures to increase substantially over at least the next several years as we expand our operations. Lease and property acquisition costs, as well as drilling operations, are very expensive, and we will need to raise substantial additional capital, through equity offerings, strategic transactions or debt financings in 2022 to commence the drilling of the Tau #2 well and avoid the expiration of a lease.

Our future capital requirements will depend on many factors, including:

We have planned operating and capital expenditures through December 2022 of approximately $10 million, which includes drilling capital expenditures and general and administrative expenses. We will need to raise funds to cover these planned operating expenditures.

To the extent we are able to raise capital through equity financings, this may be dilutive to our stockholders. Alternative forms of future financings may include preferred stock with 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 best efforts 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. There is no assurance that we can raise the capital necessary to fund our business plan. Failure to raise the required capital to fund operations, on favorable terms or at all, will have a material adverse effect on our operations, resulting in impairments of our oil and gas properties and could cause us to curtail or cease operations.

Our fiscal 2021 financial statements express substantial doubt about our ability to continue as a going concern, raising questions as to our continued existence.

We have incurred losses since our inception resulting in an accumulated deficit of approximately $60.2 million and negative working capital totaling approximately $12.1 million at September 30, 2021.  Further losses are anticipated as we continue to develop our business. To continue as a going concern, we estimate that we will need approximately $10 million to meet our obligations and planned operating expenditures through December 2022. These expenditures include anticipated drilling capital expenditures, lease rentals to the BOEM, general and administrative expenses, and costs associated with IT and seismic acquisition and processing. In addition, we plan to extend the agreements associated with our loans from related parties, the accrued interest payable on these loans, as well as the Company’s accrued liabilities. We plan to finance our operations through equity and/or debt financings, and strategic transactions to include farm-outs, asset sales or mergers. There are no assurances that financing will be available with acceptable terms, if at all. If we are not successful in obtaining financing, our 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.

We have no proved reserves and areas that we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all.

We have no proved reserves. We have identified prospects based on available seismic and geological information that indicates the potential presence of oil and natural gas. However, the areas we decide to drill may not yield oil and natural gas in commercial quantities or quality, or at all. Most of our current prospects are in various stages of evaluation that will require substantial additional seismic data reprocessing and interpretation. Even when properly used and interpreted, 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. We do not know if our prospects will contain oil and natural gas in sufficient quantities or quality to recover drilling and completion costs or to be economically viable. Even if oil and natural gas is found on our prospects in commercial quantities, construction costs of pipelines and other transportation costs may prevent such prospects from being economically viable. If one or more of our prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.

The seismic data we use are subject to non-exclusive license arrangements and may be licensed to our competitors, which could adversely affect the execution of our acquisition strategy and business plan.

Our 3-D seismic license agreements are non-exclusive, industry-standard agreements. Accordingly, the licensor of such seismic data has the right to license the same data that we acquired to our competitors, which could adversely affect our acquisition strategy and the execution of our business plan. We are not authorized to assign any of our rights under our license agreements, including a transaction with a potential joint venture partner or acquirer, without complying with the terms of the license agreements and a payment to the licensor (by us or the acquirer in the event of a change of control transaction or our partner in a joint venture transaction). However, our interpretation of this seismic data and importantly, reprocessing and the modeling of certain seismic data utilized to identify and technically support oil and gas prospects, is unique and proprietary to the Company.

3-D seismic interpretation does not guarantee that hydrocarbons are present or if present, produce in economic quantities.

We rely on 3-D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3-D seismic data may impact our drilling and operational results, and consequently our financial condition.

Our leases may be terminated if we are unable to make future lease payments or if we do not drill in a timely manner.

The failure to timely affect all lease related payments could cause the leases to be terminated by the BOEM. Net lease rental obligations on our existing prospects are expected to be approximately $0.2 million in fiscal year 2022. Our two leases have a five-year primary term and expire on June 30, 2022 and October 31, 2025, respectively. Each lease may be extended, by drilling a well capable of producing hydrocarbons and submitting a Plan of Production approved by the regulatory authorities. In addition, the terms of our leases may be extended for an additional three years, provided a well is spud targeting hydrocarbons below 25,000 feet true vertical depth (“TVD”) within the primary term of the lease. In addition, the terms of our leases may also be extended by the granting of a Subsalt Lease Term Extension, should we elect to apply and qualify for said extension on any lease(s). If we are not successful in raising additional capital, we may be unable to successfully exploit our properties, and we may lose the rights to develop these properties upon the expiration of our leases. If not successful in securing extensions, those leases will be subject to the competitive bid process in the semi-annual BOEM OCS Lease Sales.

We may not be able to develop oil and natural gas reserves on an economically viable basis.

To the extent that we succeed in discovering oil and/or natural gas reserves, we cannot assure that these reserves will be capable of production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find, develop and commercially produce oil and gas reserves, assuming we acquire leases or drilling rights. Our future reserves, if any, will depend not only on our ability to develop then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we develop and to effectively distribute our production into markets.

Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. While we will endeavor to effectively manage these conditions, we cannot be assured of doing so optimally, and we will not be able to eliminate them completely in any case. Therefore, these conditions could adversely impact our operations.

We are substantially dependent on certain members of our management and technical team.

Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying and acquiring leases and producing properties, as well as discovering and developing any oil and gas reserves. Our performance and success are dependent, in part, upon key members of our management and technical team, and their loss or departure could be detrimental to our future success. In making a decision to invest in our common stock, you must be willing to rely to a significant extent on our management’s discretion and judgment. The loss of any of our management and technical team members could have a material adverse effect on our business prospects, results of operations and financial condition, as well as on the market price of our common stock. We may not be able to find replacement personnel with comparable skills. If we are unable to attract and retain key personnel, our business may be adversely affected. We do not currently maintain key-man insurance on any member of the management team.

We are an oil and natural gas exploration and production company with limited operating history, and there can be no assurance that we will be successful in executing our business plan. We may never attain profitability.

We commenced our business activity in March 2013, when we entered into 3-D license agreements covering approximately 2.2 million acres and have entered into additional 3-D license agreements with seismic companies to acquire additional data and reprocess seismic data. While we intend to engage in the acquisition, drilling, development, and production of oil and natural gas in the future, we currently have no reserves or production. As we are a relatively new business, we are subject to all the risks and uncertainties, which are characteristic of a new business enterprise, including the substantial problems, expenses and other difficulties typically encountered in the course of its business, in addition to normal business risks, as well as those risks that are specific to the oil and gas industry. Investors should evaluate us in light of the delays, expenses, problems and uncertainties frequently encountered by companies developing markets for new products, services and technologies. We may never overcome these obstacles.

We may be unable to access the capital markets to obtain additional capital that we will require to implement our business plan, which would restrict our ability to grow.

Our current capital on hand is insufficient to enable us to fully execute our business strategy in 2022. Because we are a company with limited resources, we may not be able to compete in the capital markets with much larger, established companies that have ready access to capital. Our ability to obtain needed financing may be impaired by conditions and instability in the capital markets (both generally and in the oil and gas industry in particular), our status as a early-stage enterprise without a demonstrated operating history, the location of our leases and prices of oil and natural gas on the commodities markets (which will impact the amount of financing available to us), and/or the loss of key consultants and management. Further, if oil and/or natural gas prices decrease, then potential revenues, if any, will decrease, which may increase our requirements for capital. Some of the future contractual arrangements governing our operations may require us to maintain minimum capital (both from a legal and practical perspective), and we may lose our contractual rights if we do not have the required minimum capital. If the amount of capital we can raise is not sufficient, we may be required to curtail or cease our operations.

We have a limited operating history with significant losses and expect losses to continue for the foreseeable future.

We have incurred annual operating losses since our inception. As a result, at September 30, 2021, we had an accumulated deficit of approximately $60.2 million. We had no revenues in 2021 and do not anticipate generating revenues in fiscal 2022, or in subsequent periods unless we are successful in discovering or acquiring economically recoverable oil or gas reserves. We expect continued losses in fiscal year 2022, and thereafter until we are successful in discovering or acquiring economically recoverable oil or gas reserves.

The majority of our existing debt outstanding is payable on demand. If we are unable to repay our existing or future debt as it becomes due, we may be unable to continue as a going concern.

As of September 30, 2021, we owed John Seitz, our chief executive officer, a total of $8.7 million in notes, payable on demand and bearing interest at the rate of 5% per annum. Unpaid interest associated with these notes was $2.96 million as of September 30, 2021. In addition, approximately 16% of our outstanding common stock is controlled by Mr. Seitz. If demand for immediate payment of some or all notes were to occur, it will threaten our ability to continue as a going concern. 

Our lack of diversification increases the risk of an investment in our common stock.

Our business will focus on the oil and gas industry in commercially advantageous offshore areas of the United States. Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, factors affecting our industry, or the regions in which we operate, will likely impact us more acutely than if our business were diversified.

Strategic relationships upon which we rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully bid on and acquire properties, to discover resources, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers and partners, depends on developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable properties. Further, we must consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.

To develop our business, we will endeavor to use the relationships of our management and to enter into strategic relationships, which may take the form of joint ventures with other private parties or with local government bodies or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require that we incur expenses or undertake activities we would not otherwise incur or undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

We may not be able to effectively manage our growth, which may harm our profitability.

Our strategy envisions building and expanding our business. If we fail to effectively manage our growth, our financial results will be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems, processes, and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

If we are unable to manage our growth and our operations, our financial results could be adversely affected, which could prevent us from ever attaining profitability.

We may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to successfully integrate future acquisitions.

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer. 

Our future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to liabilities that are not indemnified, which could materially adversely affect our production, revenues and results of operations.

We may be dependent upon third party operators of any oil and natural gas properties we may acquire.

Third parties may act as the operators of our oil and natural gas wells and control the drilling and operating activities to be conducted on our properties, if and when such assets are acquired. Therefore, we may have limited control over certain decisions related to activities on our properties relating to the timing, costs, procedure, and location of drilling or production activities, which could affect the Company’s results.

We may not be able to obtain drilling rigs and other equipment and geophysical service crews necessary to exploit any oil and natural gas resources we may acquire.

We may not be able to procure the necessary drilling rigs, and related services and equipment or the cost of such items may be prohibitive. Our ability to comply with future license obligations or otherwise generate revenues from the production of operating oil and natural gas wells could be hampered as a result of this, and our business could suffer.

Risks Related to Our Industry in Which We Intend to Compete

An extended decline in oil prices and significant fluctuations in energy prices may continue indefinitely, affecting the commercial viability of our projects and negatively affecting our business prospects and viability.

The commercial viability of our projects is highly dependent on the price of oil and natural gas. Prices also affect our ability to borrow money or raise additional capital. We will need to obtain additional financing to fund our activities. Our ability to do so may be adversely affected by an extended decline in oil prices. If we are unable to obtain such financing when needed, on commercially reasonable terms, we may be required to cease our operations, which could have a materially adverse impact on the market price of our stock. An extended decline in oil prices may have a material adverse effect on our planned operations, financial condition and level of expenditures that we may ultimately have to make for the development of any oil and natural gas reserves we may acquire.

The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. In addition, the prices we receive for any future production and the levels of any future production and reserves will depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

Further, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. The price of oil has been extremely volatile, and we expect this volatility to continue for the foreseeable future. The volatility of the energy markets make it difficult to predict future oil and natural gas price movements with any certainty.

Exploration for oil and natural gas is risky and may not be commercially successful, impairing our ability to generate revenues.

Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. We may not discover oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over pressured zones (which may lead to blowouts, fires, and explosions) and tools lost in the hole, and changes in drilling plans, locations as a result of prior exploratory wells or additional seismic data and interpretations thereof, and final commercial terms negotiated with partners. Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial risk. The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, adverse weather conditions (which may be more frequent as climate changes), cost overruns, equipment shortages, mechanical difficulties, and environmental hazards (including spills and toxic gas releases). There is no assurance that we will successfully complete any wells or if successful, that the wells would be economically successful. Moreover, the successful drilling or completion of any oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. We cannot assure you that our exploration activities will result in profitable operations, the result of which will materially adversely affect our business.

Competition within our industry may adversely affect our operations.

Competition within our industry is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than our budget, which may adversely affect our ability to compete. If other companies relocate to the Gulf of Mexico region, levels of competition may increase, and our business could be adversely affected. In the exploration and production business, some of the larger integrated companies may be better able than we are to respond to industry changes including price fluctuations, oil and gas demand, political change and government regulations.

We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe impacts attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations. 

The BSEE and the BOEM have over the past decade, primarily under the Obama Administration, imposed more stringent permitting procedures and regulatory safety and performance requirements with respect to new wells drilled in federal deepwater. While, in recent years under the Trump Administration, there have been actions by BSEE or BOEM seeking to mitigate or delay certain of those more rigorous standards, we expect that the Biden Administration may reconsider rules and regulatory initiatives implemented under the Trump Administration. Compliance with any added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies under the Biden Administration are expected to continue to evaluate aspects of safety and operational performance in the United States Gulf of Mexico that could result in new, more restrictive requirements. For example, under the Trump Administration, BSEE reviewed and delayed or revised certain offshore regulations implemented during the Obama Administration with respect to the imposition of rigorous standards relating to well control. In light of the statements made by President Biden, there exists a significant risk that these Obama-era regulations, or additional, more stringent regulations impacting our business, properties and results of operations could be reimplemented or adopted during the Biden Administration. These regulatory actions, or any new rules, regulations, or legal initiatives or controls that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and costs and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in the suspension or cancellation of leases. Also, if material spill incidents were to occur in the future, the United States could elect to issue directives to temporarily cease drilling activities and, in any event, issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In 2016, the BOEM under the Obama Administration issued Notice to Lessees and Operators (“NTL”) #2016-N01 (“NTL #2016-N01”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”). While NTL #2016-N01 became effective in September 2016, it was not fully implemented as the BOEM under the Trump Administration first extended indefinitely in 2017 implementation of the NTL and subsequently rescinded the NTL in the latter half of 2020, instead electing to publish in October 2020 a proposed rule that would amend the BOEM’s financial assurance requirements. The Biden Administration is expected to review and reconsider actions made under the Trump Administration with respect to provision of financial assurance, including the rescission of NTL #2016-N01 and publication of the October 2020 proposed rulemaking. Any issuance by the Biden Administration of more stringent NTL guidance or rules relating to the provision of additional financial assurance may have a material adverse effect on us and similarly situated offshore oil and gas operators on the OCS. Moreover, the BOEM has the authority to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine mammals and endangered and threatened species.

Our oil and natural gas operations are subject to stringent federal, state, local and foreign laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection.

These laws and regulations: 

Failure to comply with these laws and regulations may result in: 

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Under these environmental laws and regulations, we could incur strict joint and several liability for the removal or remediation of previously released materials or contamination, regardless of whether we were responsible for the release or contamination and regardless of whether our operations met previous standards in the industry at the time they were conducted. Our permits require that we report any incidents that cause or could cause environmental damages.

New laws and regulations, amendment of existing laws and regulations, reinterpretation of legal requirements or increased governmental enforcement could significantly increase our capital expenditures and operating costs or could result in delays, limitations or cancelations to our exploration and production activities, which could have an adverse effect on our financial condition, results of operations, or cash flows.

Our operations are subject to numerous risks of oil and natural gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the Gulf of Mexico, our drilling activities increase capital cost. In addition, the geological complexity of the areas in which we have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success. Oil and natural gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry holes and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

Any insurance that we may acquire will likely be inadequate to cover liabilities we may incur.

Our involvement in the exploration for, and development of, oil and natural gas properties may result in our becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although we intend to obtain insurance in accordance with industry standards to address such risks, such insurance has limitations and so will be unlikely to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, we may choose not to obtain insurance to protect against specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to us. If we suffer a significant event that is not fully insured or if the insurer of such event is not solvent or denies coverage, we could be required to divert funds from capital investment or other uses towards covering our liability for such events.

Events outside of our control, including an epidemic or outbreak of an infectious disease, such as the COVID-19, may materially adversely affect our business.

We face risks related to epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees. For example, in response to COVID-19, we have reduced third party expenses and reduced capital expenditures. In addition, the effects of COVID-19 and concerns regarding its global spread could negatively impact the domestic and international demand for crude oil and natural gas, which could contribute to price volatility, impact the price we receive for oil and natural gas and materially and adversely affect the demand for and marketability of our production. The potential impact from COVID-19, both now and in the future, is difficult to predict, and the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any potential impact will depend on future developments and new information that may emerge regarding the COVID-19 infection rate or the efficacy and distribution of COVID-19 vaccines, and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control. These potential impacts, while uncertain, could adversely affect our operating results. 

Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves, to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially adversely affect our business, results of operations and financial condition.

New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We rely heavily on the use of seismic technology to identify opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected. 

Our operations are subject to various risks that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduced demand for the crude oil and natural gas that we produce.

Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHG. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. At the federal level, the U.S. Congress has from time to time considered climate change legislation, but no comprehensive climate change legislation has been adopted. The EPA, however, has adopted regulations under the existing CAA to restrict emissions of GHG. For example, the EPA imposes preconstruction and operating permit requirements on certain large stationary sources that are already potential sources of certain other significant pollutant emissions. The EPA also adopted rules requiring the monitoring and reporting of GHG emissions on an annual basis from specified large GHG emission sources in the United States, including onshore and offshore oil and natural gas production facilities. Federal agencies have also begun directly regulating emissions of methane, a GHG, from oil and natural gas operations as described above. Compliance with these rules or other could result in increased compliance costs on our operations.

Additionally, state implementation of revised air emission standards could result in stricter permitting requirements, delay, limit or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. At the international level, the United Nations-sponsored Paris Agreement requires member states to submit non-binding, individually determined emissions reduction goals every five years after 2020. On January 20, 2021 President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which became effective on February 19, 2021. 

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing federal political risks in the United States. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the elimination of subsidies provided to the fossil fuel industry, increased production of offshore wind energy and increased emphasis on climate-related risks across governmental agencies and economic sectors. The Biden Administration has also taken actions to limit oil and gas development activities on the OCS. Other actions that could be pursued by the Biden Administration include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as more stringent emissions standards for oil and gas facilities. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

There are also increasing financial risks for fossil fuel producers as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

The adoption of legislation or regulatory programs to reduce or eliminate future emissions of GHG could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce or eliminate future emissions of GHG could have an adverse effect on our business, financial condition and results of operations. Also, political, financial and litigation risks may result in our restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing the ability to continue to operate in an economic manner.

Finally, some scientists have concluded that increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such effects of climate changes were to occur, they could have an adverse effect on our financial condition and results of operations. 

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and distribution activities. For example, we depend on digital technologies to interpret seismic data, conduct reservoir modeling and record financial and other data. Our industry faces various security threats, including cyber-security threats. Cyber-security attacks in particular are increasing and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although to date we have not experienced any material losses related to cyber-security attacks, we may suffer such losses in the future. Moreover, the various procedures and controls we use to monitor and protect against these threats and to mitigate our exposure to such threats may not be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of intellectual property and other sensitive information essential to our business and could have a material adverse effect on our business prospects, reputation and financial position. 

Negative publicity may adversely impact us.

Media coverage and public statements that insinuate improper actions by us, regardless of their factual accuracy or truthfulness, may result in negative publicity, litigation or governmental investigations by regulators. Addressing negative publicity and any resulting litigation or investigations may distract management, increase costs and divert resources. Negative publicity may have an adverse impact on our reputation and the morale of our employees, which could materially adversely affect our business, financial position, results of operations, cash flows, growth prospects and stock price.

Risks Related to Investment in our Securities

There is a limited trading market for our shares. You may not be able to sell your shares if you need money.

Our common stock is traded on the OTC Markets (Pink Marketplace Tier), an inter-dealer automated quotation system for equity securities. During the three calendar months preceding filing of this report, the average daily trading volume of our common stock was approximately 1.0 million shares. As of December 20, 2021, we had approximately 190 record holders of our common stock (not including an indeterminate number of stockholders whose shares are held by brokers in “street name”). There has been limited trading activity in our stock, and when it has traded, the price has fluctuated widely. We consider our common stock to be “thinly traded” and any last reported sale prices may not be a true market-based valuation of the common stock. Stockholders may experience difficulty selling their shares if they choose to do so because of the illiquid market and limited public float for our common stock. This situation is attributable to a number of factors, including, but not limited to:

As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations of the price of our common stock. Accordingly, investors must assume they may have to bear the economic risk of an investment in our common stock for an indefinite period of time and may lose their entire investment. There can be no assurance that a more active market for our common stock will develop, or if one should develop, there is no assurance that it will be sustained. This severely limits the liquidity of our common stock and would likely have a material adverse effect on the market price of our common stock and on our ability to raise additional capital.

We may issue preferred stock.

Our Certificate of Incorporation authorizes the issuance of up to 50 million shares of “blank check” preferred stock with designations, rights and preferences determined from time to time by the Board of Directors. Accordingly, our Board of Directors is empowered, without stockholder approval, to issue preferred stock with dividend, liquidation, conversion, voting, or other rights, which could adversely affect the voting power or other rights of the holders of the common stock. In the event of issuance, the preferred stock could be utilized, under certain circumstances, as a method of discouraging, delaying or preventing a change in control of the Company. Although we have no present intention to issue any shares of its authorized preferred stock, there can be no assurance that we will not do so in the future.

Future sales of our common stock could lower our stock price.

We will likely sell additional shares of common stock to fund working capital obligations in future periods. We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock. Moreover, sales of our common stock by existing shareholders could also depress the price of our common stock.

Our common stock is subject to the “penny stock” rules of the SEC and FINRA, which makes transactions in our common stock cumbersome and may reduce the value of an investment in the stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form sets forth:

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of common stock and cause a decline in the market value of stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

In addition to the “penny stock” rules promulgated by the SEC, FINRA has adopted rules that require a broker-dealer to have reasonable grounds for believing that an investment is suitable for a customer when recommending the investment to that customer. Prior to recommending speculative low-priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit investors’ ability to buy and sell our stock and have an adverse effect on the market for our shares.

The price of our common stock will remain volatile, which could lead to losses by investors and costly securities litigation.

The trading price of our common stock is likely to be highly volatile and could fluctuate in response to factors such as:

The stock market is subject to significant price and volume fluctuations. In the past, following periods of volatility in the market price of companies’ securities, securities class action litigation has often been initiated against those companies. Litigation initiated against us, whether or not successful, could result in substantial costs and diversion of our management’s attention and resources, which could harm our business and financial condition.

We do not anticipate paying any dividends on our common stock.

Cash dividends have never been declared or paid on our common stock, and we do not anticipate such a declaration or payment for the foreseeable future. We cannot assure stockholders of a positive return on their investment when they sell their shares, nor can we assure that stockholders will not lose the entire amount of their investment in the Company.

Our certificate of incorporation could make a merger, tender offer, or proxy contest difficult.

At the annual shareholder meeting in May 2014, shareholders approved an amendment and restatement of our certificate of incorporation to (i) eliminate the ability of stockholders to act by written consent and (ii) to classify the board of directors into three classes with staggered terms. These amendments may discourage, delay or prevent a change in control.

Any of the risk factors discussed herein could have a significant material adverse effect on our business, results of operations, financial condition, or liquidity. Readers of this Report should not consider any descriptions of these risk factors to be a complete set of all potential risks that could affect GulfSlope. These factors should be carefully considered together with the other information contained in this Report and the other reports and materials filed by us with the SEC. Further, any of these risks are interrelated and could occur under similar business and economic conditions, and the occurrence of certain of them may in turn cause the emergence or exacerbate the effect of others. Such a combination could materially increase the severity of the impact of these risks on our business, results of operations, financial condition, or liquidity.

 ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

 ITEM 2. PROPERTIES

For a discussion of our oil and gas properties, see Item 1. Business.

We lease approximately 5,000 square feet of office space at our corporate headquarters at 1331 Lamar St., Suite 1665, Houston, Texas 77010. We own office equipment, office furniture, and computer equipment.

 ITEM 3. 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 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock, $0.001 par value per share, is quoted on the OTC Markets (Pink Marketplace Tier) under the symbol “GSPE.” Shares of our common stock have historically been thinly traded. As a result, our stock price as quoted by the OTC Markets may not reflect an actual or perceived value.

Holders

The number of record holders of the Company’s common stock, as of December 20, 2021, is approximately 190.

Dividends

The Company has not declared any dividends with respect to its common stock and does not intend to declare any dividends in the foreseeable future. The future dividend policy of the Company cannot be ascertained with any certainty. There are no material restrictions limiting the Company’s ability to pay cash dividends on its common stock.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information with respect to the equity compensation plans available to directors, officers, certain employees and certain consultants of the Company at September 30, 2021.

Recent Sales of Unregistered Securities

None.

 ITEM 6. SELECTED FINANCIAL DATA

Not required for smaller reporting companies.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 for a discussion of the uncertainties, risks and assumptions associated with these forward-looking statements. The following discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared on the accrual basis of accounting, whereby revenues are recognized when earned, and expenses are recognized when incurred. You should read this management’s discussion and analysis of our financial condition and results of operations in conjunction with our historical financial statements included elsewhere in this Annual Report. Our future results could differ materially from our historical results due to a variety of factors, many of which are out of our control.

 Overview

GulfSlope Energy, Inc. is an independent crude oil and natural gas exploration and production company whose interests are concentrated in the United States Gulf of Mexico federal waters. We are a technically driven company and we use our licensed 2.2 million acres of advanced three-dimensional (“3-D”) seismic data to identify, evaluate, and acquire assets with attractive economic profiles. GulfSlope Energy commenced commercial operations in March 2013. GulfSlope Energy was originally organized as a Utah corporation in 2004 and became a Delaware corporation in 2012.

We have focused our operations in the United States Gulf of Mexico because we believe this area provides us with favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic databases, extensive infrastructure, relatively favorable royalty regime, and an attractive acquisition market and because our management and technical teams have significant experience and technical expertise in this geologic province. Additionally, we licensed 2.2 million acres of advanced 3-D seismic data, a significant portion of which has been enhanced by new, state-of-the-art reprocessing and noise attenuation techniques including reverse time migration depth imaging. We have used our broad regional seismic database and our reprocessing efforts to generate and high-grade oil and natural gas prospects. The use of our extensive seismic database, coupled with our ability, knowledge, and expertise to effectively reprocess this seismic data, allows us to further optimize our drilling operations and to effectively evaluate acquisition and joint venture opportunities. We consistently assess our prospect inventory in order to deploy capital as efficiently as possible. We have given preference to areas with water depths of 450 feet or less where production infrastructure already exists, which will allow for any discoveries to be developed rapidly and cost effectively with the goal to reduce economic risk while increasing returns.

Technical Strategy

We believe that a major obstacle to identifying potential hydrocarbon accumulations globally has been the inability of seismic technology to accurately image deeper geologic formations because of overlying massive, extensive, and complex salt bodies. Large and thick laterally extensive subsurface salt layers highly distort the seismic ray paths traveling through them, which often has led to misinterpretation of the underlying geology and the potential major accumulations of oil and gas. We believe the opportunity exists for a technology-driven company to extensively apply advanced seismic acquisition and processing technologies, with the goal of achieving attractive commercial discovery rates for exploratory wells, and their subsequent appraisal and development, potentially having a very positive impact on returns on invested capital. These tools and techniques have been proven to be effective in deep water exploration and production worldwide, and we are using them to identify and drill targets below the salt bodies in an area of the shallower waters of the Gulf of Mexico where industry activity has largely been absent for over 20 years. 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 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 two leases and we are evaluating the acquisition of additional leases in our core area. Our two leases have a five-year primary term and expire on June 30, 2022 and October 31, 2025. BOEM’s regulatory framework provides multiple options for leaseholders to apply to receive extensions of lease terms under specified conditions. GulfSlope is exploring all options contained in BOEM’s regulatory framework to extend the terms of the leases. Additional prospective acreage can be obtained through lease sales, farm-in, or purchase. As is consistent with a prudent and successful exploration approach, we believe that additional seismic licensing, acquisition, processing, and/or interpretation may become highly advantageous, in order to more precisely define the most optimal drillable location(s), particularly for development of discoveries.

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

Drilling and other Exploratory and Development Strategies

Our plan has been to partner with other entities which could include oil and gas companies and/or financial investors. Our goal is to diversify risk and minimize capital exposure to exploration drilling costs. We expect a portion of our exploration costs to be paid by our partners through these transactions, in return for our previous investment in prospect generation and delivery of an identified prospect on acreage we control. Such arrangements are a commonly accepted industry method of proportionately recouping pre-drill cost outlays for seismic, land, and associated interpretation expenses. We cannot assure you, however, that we will be able to enter into any such arrangements on satisfactory terms. In any drilling, we expect that our retained working interest will be adjusted based upon factors such as geologic risk and well cost. Early monetization of a discovered asset or a portion of a discovered asset is an option for the Company as a means to fund development 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.

Recent Developments

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

The 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 allochthonous 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 was designed to test multiple Miocene horizons trapped against a well-defined salt flank, including equivalent reservoir sands discovered and developed at the nearby Mahogany Field. The surface location for Tau was located in 305 feet of water. In January 2019, the Tau well experienced an underground control of well event and as a result, an insurance claim was filed with the insurance Underwriters for a net amount of approximately $10.8 million for 100% working interest. The insurance claim was subsequently approved. On May 13, 2019, GulfSlope announced the Tau No. 1 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 that depth, but hydrocarbon shows were encountered. Complex geomechanical conditions required two by-pass wellbores, one sidetrack wellbore, and eight casing strings to reach the depth of 15,254 feet. Equipment limitations prevented further drilling at that time. In addition, the drilling rig had contractual obligations related to another operator. Due to these factors, the Company elected to plug the well in a manner that would allow for re-entry at a later time.

Outlook

In the first quarter of 2020, the COVID-19 outbreak spread quickly across the globe. Federal, state and local governments mobilized to implement containment mechanisms and minimize impacts to their populations and economies. Various containment measures, such as stay-at-home orders, closures of restaurants and banning of group gatherings resulted in a severe drop in general economic activity, as well as a corresponding decrease in global energy demand. Additionally, the risks associated with COVID-19 impacted our workforce and the way we meet our business objectives. Due to concerns over health and safety, we asked our employees to work remotely. In 2021 we began to plan a process to phase employees to return to the office. Working remotely has not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of these measures. In addition, actions by the Organization of Petroleum Exporting Countries and other high oil exporting countries like Russia (“OPEC+”) have negatively impacted crude oil prices throughout 2020 and early 2021. These rapid and unprecedented events pushed crude oil storage near capacity and driven prices down significantly. On January 27, 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the elimination of subsidies provided to the fossil fuel industry, increased production of offshore wind energy and increased emphasis on climate-related risks across governmental agencies and economic sectors. The Biden Administration has also taken actions to limit oil and gas development activities on the OCS. Other actions that could be pursued by the Biden Administration include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as more stringent emissions standards for oil and gas facilities. These events have been the primary cause of the significant supply-and-demand imbalance for oil, first significantly lowering oil pricing and later significantly increasing oil pricing. The uncertainty in the trajectory of oil and gas prices and in future government actions, has greatly affected energy companies plans and budgets and may continue to exist in future periods. The Company has evaluated the effect of these factors on its business and the Company has determined that these factors will most likely cause a delay in the Company’s 2022 drilling program. The Company continues to monitor the economic environment and evaluate its continuing impact on the business.

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 two lease blocks in the U.S. Gulf of Mexico, which we believe may potentially contain economically recoverable reserves.

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.

Results of Operations for the Year Ended September 30, 2021 compared to September 30, 2020

We had no sales during the year ended September 30, 2021 and 2020. Impairment of oil and gas properties and capitalized exploration costs for the year ended September 30, 2021 was approximately $0.4 million compared to approximately $2.4 million for the year ended September 30, 2020. The impairment of approximately $0.4 million for the year ended September 30, 2021 resulted from the relinquishment of a lease and the write off of related capital costs and the impairment of approximately $2.4 million for the year ended September 30, 2020 resulted from the expiration of leases and the write-off of related capitalized costs. General and administrative expenses were approximately $1.5 million for the year ended September 30, 2021 compared to approximately $1.1 million for the year ended September 30, 2020. Interest expense was approximately $554,000 for the year ended September 30, 2021, as compared to approximately $39,000 for the year ended September 30, 2020 net of approximately $1.1 million of interest capitalized to unevaluated oil and natural gas properties during 2020. Gain on extinguishment of debt was approximately $406,000 for the year ended September 30, 2021 compared to a loss of $1.5 million for the year ended September 30. 2020. Loss on derivative financial instrument was approximately $177,000 for the year ended September 30, 2021 compared to a gain of approximately $2.6 million for the year ended September 30, 2020.

We had a net loss of approximately $2.2 million for the year ended September 30, 2021, compared to a net loss of approximately $2.4 million for the year ended September 30, 2020.

The basic loss per share for the year ended September 30, 2021 was $0.00, compared to a net loss per share of $0.00 for the year ended September 30, 2020.

For the year ended September 30, 2021, cash used in operating activities totaled $1.6 million compared to $0.4 million used in operating activities in fiscal 2020.

For the year ended September 30, 2021, cash provided by investing activities was $0.2 million compared to $5.1 million provided by investing activities in fiscal 2020. For the year ended September 30, 2021 insurance proceeds received were approximately $0.2 million and spending for exploration activities was $0.1 million. Insurance proceeds received were approximately $7.5 million and spending for exploration wells in process was approximately $2.6 million in fiscal 2020.

For the year ended September 30, 2021, cash used in financing activities was approximately $0.3 million compared to approximately $2.7 million cash used in financing activities for the year ended September 30, 2020. For fiscal 2021, approximately $0.3 million of promissory notes were paid. For fiscal 2020, approximately $0.5 million of proceeds from promissory notes were received and $3.2 million of promissory notes were paid.

As of September 30, 2021, the Company’s cash balance was approximately $1.5 million compared to approximately $3.2 million cash balance as of September 30, 2020. The Company’s fiscal 2021 cash decrease of approximately $1.7 million was primarily due to its net cash used in operating activities of approximately $1.6 million, cash received in investing activities of approximately $0.2 million and cash used in financing activities of approximately $0.3 million.

Liquidity and Capital Resources

The Company has incurred accumulated losses for the period from inception to September 30, 2021, of approximately $60.2 million, and has negative working capital of approximately $12.1 million. For the year ended September 30, 2021, the Company has generated losses of approximately $2.2 million and negative cash flows from operations of approximately $1.6 million. As of September 30, 2021, we had $1.5 million of cash on hand. The Company estimates that it will need to raise a minimum of $10 million to meet its obligations and planned expenditures through December 2022. The $10 million is comprised primarily of drilling capital expenditures as well as general and administrative expenses. It does not include any amounts due under outstanding debt obligations, which amounted to $12.0 million of current principal and interest as of September 30, 2021. The Company plans to finance its operations through equity and/or debt financings, and strategic transactions to include farm-outs, asset sales or mergers. Our policy has been to periodically raise funds through the sale of equity securities 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 year ended September 30, 2021, the Company used approximately $1.6 million of net cash in operating activities, compared with approximately $0.4 million of net cash used in operating activities for the year ended September 30, 2020. For the year ended September 30, 2021, cash provided by investing activities was approximately $0.2 million compared to approximately $5.1 million of cash provided by investing activities for the year ended September 30, 2020. For the year ended September 30, 2021, we used approximately $0.3 million of net cash in financing activities, compared with approximately $2.7 million used in financing activities for year ended September 30, 2020.

We will need to raise additional funds to cover expenditures planned for 2022, 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.

We are party to various contractual obligations such as our office lease obligation that is disclosed in the financial statements. We do not have any other material contractual obligations. Other immaterial obligations may be reflected in our accompanying consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2021.

Critical Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.  The critical accounting estimates include impairment considerations of long-lived assets including oil and natural gas properties and assumptions used in valuing our derivative financial instruments.

Recent Accounting Pronouncements Not Yet Adopted

In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06), which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, ASU 2020-06 requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS), which is consistent with the Company’s accounting treatment under the current standard. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted for fiscal years beginning after December 15, 2020. ASU No. 2020-06 can be adopted on either a fully retrospective or modified retrospective basis. The adoption of ASU 2020-06 is not expected to have a material impact on the Company’s financial statements or disclosures.

In May 2021, the FASB issued ASU 2021-04, Earnings Per Share (Topic 260), Debt-Modifications and Extinguishments (Subtopic 470-50), Compensation-Stock Compensation (Topic 718), and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options. ASU 2021-04 provides clarification and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification or exchange. ASU 2021-04 introduces a recognition model that comprises four categories of transactions and the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to equity issuance and debt origination or modification). ASU 2021-04 is effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. An entity should apply the guidance provided in ASU 2021-04 prospectively to modifications or exchanges occurring on or after the effective date. Early adoption is permitted for all entities, including adoption in an interim period. If an entity elects to early adopt ASU 2021-04 in an interim period, the guidance should be applied as of the beginning of the fiscal year that includes that interim period. The adoption of ASU 2021-04 is not expected to have a material impact on the Company’s financial statements or disclosures.

The Company has evaluated all other recent accounting pronouncements and believes either they are not applicable or that none of them will have a significant effect on the Company’s financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required for smaller reporting companies.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

GulfSlope Energy, Inc.

TABLE OF CONTENTS

Report of Independent Registered Public Accounting Firm

Shareholders and Board of Directors

GulfSlope Energy, Inc.

Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying balance sheets of GulfSlope Energy, Inc. (the “Company”) as of September 30, 2021 and 2020, the related statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company at September 30, 2021 and 2020, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Uncertainty

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As described in Note 2 to the financial statements, the Company has accumulated losses, and further losses are anticipated in developing the Company’s business, which raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Pannell Kerr Forster of Texas, P.C.

We served as the Company’s auditor since November 2019.

Houston, Texas

December 29, 2021

 GulfSlope Energy, Inc.

BALANCE SHEETS

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

GulfSlope Energy, Inc.

STATEMENTS OF OPERATIONS

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

GulfSlope Energy, Inc.

STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended September 30, 2021 and 2020

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

GulfSlope Energy, Inc.

STATEMENTS OF CASH FLOWS

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

GulfSlope Energy, Inc.

Notes to the Financial Statements

NOTE 1 – ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Organization

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 two 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.

(b) Basis of Presentation

The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and the instructions to Form 10-K and Regulation S-X published by the US Securities and Exchange Commission (the “SEC”). The accompanying financial statements include the accounts of the Company.

(c) Cash

The Company considers all short-term highly liquid investments with an original maturity at the date of purchase of three months or less to be cash equivalents. There were no cash equivalents at September 30, 2021 and 2020, respectively.

(d) 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, we assess the receivable and the underlying asset for recovery. As of September 30, 2021 and 2020, no allowance was recorded. Accounts receivable were nil and approximately $0.4 million on September 30, 2021 and 2020, respectively. 

(e) 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 by management and third party consultants 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 is currently evaluating one well for proved reserves and remain pending the outcome of exploration activities involving the drilling of the Tau No. 2 well (twin well).  Accordingly, this costs is included as suspended well costs at September 30, 2021 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 upon final evaluation.

As of September 30, 2021, the Company’s oil and gas properties consisted of unproved properties, wells in process and no proved reserves.

(f) Asset Retirement Obligations

The Company’s asset retirement obligations will represent the present value of the estimated future costs associated with plugging and abandoning oil and natural gas wells, removing production equipment and facilities and restoring the seabed in accordance with the terms of oil and gas leases and applicable state and federal laws. Determining asset retirement obligations requires estimates of the costs of plugging and abandoning oil and natural gas wells, removing production equipment and facilities and restoring the sea bed as well as estimates of the economic lives of the oil and gas wells and future inflation rates. The resulting estimate of future cash outflows will be discounted using a credit-adjusted risk-free interest rate that corresponds with the timing of the cash outflows. Cost estimates will consider historical experience, third party estimates, the requirements of oil and natural gas leases and applicable local, state and federal laws, but do not consider estimated salvage values. Asset retirement obligations will be recognized when the wells drilled reach total depth or when the production equipment and facilities are installed or acquired with an associated increase in proved oil and gas property costs. Asset retirement obligations will be accreted each period through depreciation, depletion and amortization to their expected settlement values with any difference between the actual cost of settling the asset retirement obligations and recorded amount being recognized as an adjustment to proved oil and gas property costs. Cash paid to settle asset retirement obligations will be included in net cash provided by operating activities from continuing operations in the statements of cash flows. On a quarterly basis, when indicators suggest there have been material changes in the estimates underlying the obligation, the Company reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. At least annually, the Company will assess all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. Future revisions could occur due to changes in estimated costs or well economic lives, or if federal or state regulators enact new requirements regarding plugging and abandoning oil and natural gas wells. The Company drilled two well bores in 2018 and 2019 and these wellbores were both plugged with no further future cost required and as such, the asset retirement obligation was completely extinguished.

(g) Property and Equipment

Property and equipment are carried at cost and include expenditures for new equipment and those expenditures that substantially increase the productive lives of existing equipment and leasehold improvements. Maintenance and repair costs are expensed as incurred. Property and equipment are depreciated on a straight-line basis over the assets’ estimated useful lives. Fully depreciated property and equipment still in use are not eliminated from the accounts.

The Company assesses the carrying value of its property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability is measured by comparing estimated undiscounted cash flows, expected to be generated from such assets, to their net book value. If net book value exceeds estimated cash flows, the asset is written down to its fair value, determined by the estimated discounted cash flows from such asset. When an asset is retired or sold, its cost and related accumulated depreciation and amortization are removed from the accounts. The difference between the net book value of the asset and proceeds on disposition is recorded as a gain or loss in our statements of operations in the period in which they occur. 

 (h) Income Taxes

Deferred tax assets and liabilities are recognized for the temporary differences between the financial reporting basis and tax basis of the Company’s assets and liabilities at enacted tax rates expected to be in effect when such amounts are realized or settled. A valuation allowance is provided if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The Company’s policy is to recognize potential interest and penalties as a component of income tax expense when incurred.

(i) Stock-Based Compensation

The Company records expenses associated with the fair value of stock-based compensation. For fully vested and restricted stock grants, the Company calculates the stock-based compensation expense based upon estimated fair value on the date of grant. For stock warrants and options, the Company uses the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. Changes in these assumptions can materially affect the fair value estimate.

(j) Stock Issuance

The Company records stock-based compensation awards issued to non-employees and other external entities for goods and services at either the fair market value of the goods received or services rendered or the instruments issued in exchange for such services, whichever is more readily determinable.

(k) Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. 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, convertible notes and restricted stock. The number of potential common shares outstanding relating to stock options, warrants, and restricted stock is computed using the treasury stock or if-converted method.

As the Company has incurred losses for the years ended September 30, 2021 and 2020, the potentially dilutive shares are anti-dilutive and thus not added into the EPS calculations. As of September 30, 2021 and 2020, there were 297,823,015 and 259,392,057 potentially dilutive shares, respectively.  

(l) 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.

(m) Use of Estimates

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

(n) Recent Accounting Pronouncements Not Yet Adopted

In August 2020, the FASB issued ASU No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06), which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Additionally, ASU 2020-06 requires the application of the if-converted method to calculate the impact of convertible instruments on diluted earnings per share (EPS), which is consistent with the Company’s accounting treatment under the current standard. ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted for fiscal years beginning after December 15, 2020. ASU No. 2020-06 can be adopted on either a fully retrospective or modified retrospective basis. The adoption of ASU 2020-06 is not expected to have a material impact on the Company’s financial statements or disclosures.

In May 2021, the FASB issued ASU 2021-04, Earnings Per Share (Topic 260), Debt-Modifications and Extinguishments (Subtopic 470-50), Compensation-Stock Compensation (Topic 718), and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40): Issuer’s Accounting for Certain Modifications or Exchanges of Freestanding Equity-Classified Written Call Options. ASU 2021-04 provides clarification and reduces diversity in an issuer’s accounting for modifications or exchanges of freestanding equity-classified written call options (such as warrants) that remain equity classified after modification or exchange. An issuer measures the effect of a modification or exchange as the difference between the fair value of the modified or exchanged warrant and the fair value of that warrant immediately before modification or exchange. ASU 2021-04 introduces a recognition model that comprises four categories of transactions and the corresponding accounting treatment for each category (equity issuance, debt origination, debt modification, and modifications unrelated to equity issuance and debt origination or modification). ASU 2021-04 is effective for all entities for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. An entity should apply the guidance provided in ASU 2021-04 prospectively to modifications or exchanges occurring on or after the effective date. Early adoption is permitted for all entities, including adoption in an interim period. If an entity elects to early adopt ASU 2021-04 in an interim period, the guidance should be applied as of the beginning of the fiscal year that includes that interim period. The adoption of ASU 2021-04 is not expected to have a material impact on the Company’s financial statements or disclosures.

The Company has evaluated all other recent accounting pronouncements and believes either they are not applicable or that none of them will have a significant effect on the Company’s financial statements.

NOTE 2 – LIQUIDITY/GOING CONCERN

The Company has incurred accumulated losses as of September 30, 2021, of $60.2 million. Further losses are anticipated in developing our business, and there exists substantial doubt about the Company’s ability to continue as a going concern. As of September 30, 2021, the Company had $1.5 million of cash on hand. The Company estimates that it will need to raise a minimum of $10 million to meet its obligations and planned expenditures through December 2022. The Company plans to finance operations and planned expenditures through equity and/or debt financings, and strategic transactions to include farm-outs, asset sales or mergers. The Company also plans to extend the agreements associated with all loans, the accrued interest payable on these loans, as well as the Company’s accrued liabilities. There are no assurances that financing will be available with acceptable terms, if at all. If the Company is not successful in obtaining financing, 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.

NOTE 3 – OIL AND NATURAL GAS PROPERTIES

The Company currently has under lease two federal Outer Continental Shelf blocks and has licensed 2.2 million acres of three-dimensional (3-D) seismic data in its area of concentration. Our leases expire June 30, 2022 and October 31, 2025, respectively.

The Company, as the operator of two wells drilled in the Gulf of Mexico, has incurred tangible and intangible drilling costs for the wells in process and has billed its working interest partners for their respective share of the drilling costs to date. The intangible drilling and all other costs related to the first well have been impaired. The second well, Tau No. 1, was drilled to a measured depth of 15,254 feet, as compared to the originally permitted 29,857 foot measured depth. Producible hydrocarbon zones were not established to that depth, but hydrocarbon shows were encountered. Complex geomechanical conditions required two by-pass wellbores, one sidetrack wellbore, and eight casing strings to reach that depth. Equipment limitations prevented further drilling. In addition, the drilling rig had contractual obligations related to another operator. The Company elected to plug this well in a manner that would allow for re-entry at a later time. The Company is evaluating various options related to future operations in this wellbore and testing of the deeper Tau prospect. The Company plans to re-drill this prospect within the next twelve months. The effects of the COVID-19 pandemic on offshore operations is influencing the potential timing of a re-drill.

In January 2019, the Tau No. 1 well experienced an underground control of well event and as a result, the Company filed an insurance claim pursuant to its insurance policy with its insurance underwriters (the “Underwriters”). The total amount of the claim was approximately $10.8 million for 100% working interest after the insurance deductible amount. During 2019, 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 twelve months ended September 30, 2020, the accrued payable was settled by the issuance to the working interest partner of approximately 38.4 million shares of the Company’s common stock.

In May 2019, the Tau No. 1 well experienced a second underground control of well event and as a result, the Company filed an insurance claim. The claim was related to a subsurface well occurrence that happened during the drilling of the Company‘s Tau No. 1 well on May 5, 2019 at a measured depth of 15,254 feet. The Company subsequently controlled the occurrence and ceased drilling operations and plugs were placed in the well to meet regulatory requirements prior to rig release. Pursuant to the Policy terms and conditions, the Underwriters were obligated to reimburse GulfSlope for qualified actual costs and expenses incurred to (i) regain control of the well, and (ii) restore or re-drill the well to 15,254 feet. Total costs and expenses to regain control of the well were determined to be approximately $4.8 million (net of deductible) for 100% working interest and all of this amount had been received as of September 30, 2020. GulfSlope’s share of this amount was approximately $1.2 million.

In November 2019, an agreement was reached with a working interest partner whereby the working interest partner re-conveyed to the Company their 5% interest in Tau No. 1 and Canoe wells in exchange for the release of claims and the Company foregoing collection of accounts receivable owed by the working interest partner. As a result of this agreement approximately $3.6 million of accounts receivable was reclassified to oil and gas properties – unproved during the year ended September 30, 2020.

On July 27, 2020, the Company entered into a settlement with the Underwriters of a well control events insurance policy covering certain claims associated with the drilling of the Company’s Tau Prospect during May 2019. In accordance with the settlement, in lieu of the insurer paying for the redrill of the well and for a complete release of any further liability under the insurance policy, the Company will receive approximately $6.6 million in cash net to its 25% working interest. At September 30, 2020, approximately $6.4 million has been received and all of this amount has been received through the filing date of this report. The Company intends to apply the proceeds from the insurance settlement to pay amounts due on the Convertible Debentures and other payables, as well as fund other general corporate purposes including expenditures associated with the Company’s drilling program.

As of September 30, 2021, the Company’s oil and natural gas properties consisted of unproved properties, wells in process and no proved reserves. During the years ended September 30, 2021 and 2020, the Company capitalized approximately $0.15 million and $2.3 million, net of impairment of nil and approximately $0.6 million, respectively. Approximately $0.01 million and $0.3 million of general and administrative expenses, respectively, was capitalized to oil and natural gas properties for the years ended September 30, 2021 and 2020. Conversely, during the year ended September 30, 2020, the Company received certain vendor credits totaling approximately $2.1 million (net to the Company’s interest) and insurance claim proceeds of approximately $7.5 million which the Company applied against oil and natural gas properties in the condensed balance sheet.

During the twelve months ended September 30, 2021 and 2020, the Company incurred impairment charges of approximately $0.4 million and approximately $2.4 million, respectively, resulting from the relinquishment or expiration of oil and natural gas leases.

NOTE 4 – PROPERTY AND EQUIPMENT

Property and equipment consist of the following at September 30, 2021 and 2020:

Depreciation is computed on a straight-line basis over the estimated useful lives of the assets, which were as follows:

Depreciation expense was $6,667 and $6,667 for the years ended September 30, 2021 and 2020, respectively.

NOTE 5 – INCOME TAXES 

The provision for income taxes consists of the following for the years ended September 30, 2021 and 2020:

The difference between the actual income tax provision versus tax computed at the statutory rate is as follows for the years ended September 30, 2021 and 2020, respectively:

The Company does not have any material uncertain tax positions. The Company’s policy is to recognize interest and penalties accrued related to unrecognized tax benefits as a component of income tax expense (benefit). For the years ended September 30, 2021 and 2020, the Company did not recognize any interest or penalties, nor did we have any interest or penalties accrued as of September 30, 2021 and 2020 relating to unrecognized benefits. Deferred income tax assets and liabilities at September 30, 2021 and 2020, respectively, consist of the following:

Schedule of deferred income tax assets and liabilities

The Company’s valuation allowance decreased $661,812 during the year ended September 30, 2021 and increased $2,399,698 during the year ended September 30, 2020.

At September 30, 2021, the Company had approximately $62.0 million of net operating losses (“NOL”), approximately $0.1 million of which will expire from 2024 to 2031, approximately $33.2 million of which will expire from 2032 to 2038, and approximately $28.7 million of which can be carried forward indefinitely. $33.4 million of the Company’s NOLs are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of limitations imposed by the Tax Cut and Jobs Act (TCJA) of 2017 and Coronavirus Aid, Relief, and Economic Security Act (CARES) of 2020. $28.6 million of the Company’s NOLs are allowable as a deduction against 80 percent of future taxable income.

The tax years ended September 30, 2018 through 2021 are open for examination for federal income tax purposes and by other major taxing jurisdictions to which we are subject.

NOTE 6 – 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 September 30, 2021 and 2020, the total amount owed to John Seitz is $8,675,500. This amount is included in loans from related parties within the condensed balance sheets. There was approximately $2.96 million and $2.52 million, respectively, of unpaid interest associated with these loans included in accrued interest payable within the balance sheet as of September 30, 2021 and 2020.

On November 15, 2016, a family member of the CEO entered into a $50,000 convertible promissory note with associated warrants under the same terms received by other investors (see Note 7).

Domenica Seitz CPA, who is related to the CEO, has provided accounting services to the Company, as a consultant and beginning October 2020 as an employee. During the years ended September 30, 2021 and 2020, the services provided were valued at approximately $75,000 and $60,000, respectively. The amount owed to this related party totals approximately $346,000 as of September 30, 2021 and 2020, respectively. The Company has accrued these amounts, and they have been reflected in related party payable in the September 30, 2021 and 2020 financial statements.

NOTE 7 – CONVERTIBLE NOTES PAYABLE

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

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 each year at maturity and is currently April 30, 2022), an annual interest rate of 8% and can be converted at the option of the holder at a conversion price of $0.025 per share. In addition, the convertible notes will automatically convert if a qualified equity financing of at least $3.0 million occurs before maturity and such mandatory conversion price will equal the effective price per share paid in the qualified equity financing. The remaining note balances as of September 30, 2021 and 2020 were $277,000, including $50,000 from related parties, with remaining unamortized debt discounts of approximately $50,000 and $11,000, respectively. Debt discount amortization for the years ended September 30, 2021 and 2020 was approximately $48,000 and $8,100, respectively. Accrued interest as of September 30, 2021 and 2020 related to these notes was approximately $116,000 and $94,000 respectively. As noted above, the maturity date related to these notes was extended to April 30, 2022. In consideration for the extension of the notes, the Company extended the term of the related warrants until April 30, 2022 and recognized approximately $87,000 of additional debt discount which represented the incremental fair value of the modified warrants over the pre-modification warrants.

Delek Note

On March 1, 2019, the Company entered into a term loan agreement with Delek GOM Investments LLC (“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 7.0% 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 matured 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.

The Company accounted for the October 2019 transaction as an extinguishment of the prior note given the addition of the substantive conversion feature discussed above. In addition, The Company concluded that the embedded conversion feature within the note requires derivative accounting treatment under ASC 815, Derivatives and Hedging due to the potential variable conversion feature which lacks an explicit limit on the number of shares that may be required 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.

On September 30, 2020, the Company and Delek settled this convertible note and related accrued interest of $129,211 for a cash payment of $1,220,548 and the issuance 17,500,000 shares of common stock. The shares were not issued until October 2020 and are reflected on the balance sheet as additional paid in capital – shares to be issued. The fair value of the embedded conversion option was zero as of September 30, 2020.  The Company recognized a $35,045 gain on extinguishment of debt as a result of the settlement.

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 of convertible debentures (“Convertible Debentures”) and associated warrants. On June 21, 2019, approximately $2,100,000 (“Tranche 1”) of Convertible Debentures were purchased with other tranches closing on August 7, 2019 for $400,000 (“Tranche 2”) and November 6, 2019 (“Tranche 3”) for $500,000. All tranches accrue interest at 8%, and mature one year after each respective closing date, and are convertible at the option of the holder any time after issuance into common stock at a conversion rate of the lesser of: (1) $0.05 per share; or (2) 80% of the lowest volume weighted adjusted price (as reported by Bloomberg, LP) for the ten consecutive trading days immediately preceding conversion, and in the event of default the conversion rate adjusts to 60% of the lowest volume weighted average price in the previous 20 trading days.

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

The Company evaluated the conversion feature and concluded that it should be bifurcated and accounted for as a derivative liability due to the variable conversion feature which does not contain an explicit limit on the number of shares that are required to be issued upon conversion. In addition, the Company concluded the warrants required treatment as derivative liabilities as the Company could not assert it has sufficient authorized but unissued shares to settle the warrants upon exercise when taking into account other stock-based commitments including the Convertible Debentures. Accordingly, the embedded conversion feature and warrants were recorded at fair value at issuance and are subsequently remeasured to fair value each reporting period. The Company recognized a gain of approximately $2,400,000 for the year ended September 30, 2020, related to the change in fair value of the embedded conversion feature and warrants, respectively.

In June 2020, the Company extended the maturity dates of Tranche 1 and Tranche 2 to August 21, 2020 in exchange for a cash payment of $50,000. The extension was treated as a modification for accounting purposes which resulted in the $50,000 being recognized as an additional debt discount allocated on a pro-rata basis between Tranche 1 and Tranche 2 and will be amortized using the effective interest method over the remaining life of the respective tranches.

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

The Company further agreed to reduce the exercise price on the warrants held by the holder representing the right to purchase an aggregate of 50,000,000 shares of common stock of the Company from $0.04 per share to $0.02 per share in exchange for the elimination of anti-dilution provisions contained in the warrants. The value of this modification is approximately $16,000.

During the year ended September 30, 2020, the lender converted approximately $1,200,000 of principal of Tranche 1 and approximately $139,000 of accrued interest into common stock. The common stock issued was recorded at its fair value on the dates of conversion which totaled approximately $2.2 million and a loss on extinguishment of debt and related derivative liability was recognized for approximately $1.0 million. The remaining balance of the convertible debenture at September 30, 2020 was $300,000.

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.

NOTE 8 – NOTES PAYABLE

Schedule of notes payable

PPP Loan 

On April 16, 2020, the Company entered into a promissory note evidencing an unsecured $100,300 loan under the Paycheck Protection Program (the “PPP Loan”). The Paycheck Protection Program was established under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and is administered by the U.S. Small Business Administration. The PPP Loan is being made through Zions Bancorporation, N.A. dba Amegy Bank. The PPP Loan is scheduled to mature on April 16, 2025 and has a 1.00% interest rate. No payments are due on the PPP Loan until October 16, 2021, although interest will continue to accrue during the deferment period. Beginning October 16, 2021, the Company will pay 43 equal monthly installments of principal and interest in the amount necessary to fully amortize the PPP Loan through the maturity date. Under the terms of the CARES Act, all or a portion of the PPP Loan may be forgiven. Such forgiveness will be determined, subject to limitations, based on the use of loan proceeds for payroll costs, mortgage interest, rent or utility costs. No assurance is provided that the Company will obtain forgiveness of the PPP Loan in whole or in part. At September 30, 2020 accrued interest of approximately $420 was included in accrued interest payable. In December 2020 the Small Business Administration (SBA) approved forgiveness of the Company’s PPP Loan plus accrued interest.

Note Payable 

From August 2015 through February 2016 the Company entered into promissory notes whereby it borrowed a total of $267,000 from Dr. Ronald Bain, its former president and chief operating officer, and his affiliate ConRon Consulting, Inc. These notes are not convertible, due on demand and bear interest at the rate of 5% per annum. In August 2020 the principal was paid in full and interest of approximately $67,000 was forgiven by the noteholder.

Insurance Note Payable

In November 2019, the Company purchased an insurance policy for approximately $241,000 and financed $220,629 of the premium by executing a note payable at an interest rate of 5.6%. The balance of the note payable as of September 30, 2020, is approximately $21,000 and is included in the Notes Payable balance in the condensed balance sheet.

NOTE 9 – Fair Value Measurement

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

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

Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company’s derivative financial instruments that were accounted for at fair value on a recurring basis as of September 30, 2021 and 2020:

The change in derivative financial instruments for the twelve months ended September 30, 2021 and 2020 is as follows:

Non-recurring fair value assessments include impaired oil and natural gas property assessments and stock-based compensation. During the year ended September 30, 2021, the Company recorded an impairment charge of approximately $0.4 million and approximately $97,000 of stock-based compensation expense. During the year ended September 30, 2020, the Company recorded an impairment charge of approximately $2.4 million and stock-based compensation expense of approximately $1.0 million, approximately $0.5 million of which was capitalized to oil and gas properties 

NOTE 10 – COMMON STOCK/PAID IN CAPITAL  

Year Ended September 30, 2021

As discussed in Note 7, in October 2020, the Company issued approximately 17.5 million common shares with a fair value of approximately $0.1 million related to the extinguishment of the Delek Note. Such shares were reflected on the September 30, 2020 balance sheet as additional paid in capital – shares to be issued. 

Year Ended September 30, 2020

As discussed in Note 7, the Company issued approximately 120 million common shares with a fair value of approximately $2.2 million upon partial conversions of the notes and related accrued interest during the year ended September 30, 2020. The common shares were valued based upon the closing common share prices on the respective conversion dates.

In addition, during the year ended September 30, 2020, 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. 

As discussed in Note 7, in 2019 the Company issued warrants to purchase an aggregate of 50 million shares of common stock at an exercise price of $0.02 per share. Such warrants expire in approximately 2.7 years.

NOTE 11 – STOCK-BASED COMPENSATION

Stock-based compensation cost is measured at the grant date, based on the estimated fair value of the award using the Black Scholes option pricing model, and is recognized over the vesting period. The Company recognized approximately $97,000 and $968,000 in stock-based compensation expense for the years ended September 30, 2021 and 2020, respectively. None of these costs were capitalized to unproved properties for the year ended September 30, 2021 and approximately $498,000 were capitalized to unproved properties for year ended September 30, 2020, with the remainder recorded as general and administrative expenses. During the year ended September 30, 2021, 41.5 million options were granted at an exercise price of $0.004 with a vesting schedule of 50% six months and 50% one year after grant. The fair value of the options computed using Black Scholes was approximately $129,000.

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

The following table summarizes the Company’s stock option activity during the year ended September 30, 2021:

As of September 30, 2021, there was approximately $32,000 of unrecognized stock-based compensation expense.

NOTE 12 – COMMITMENTS AND CONTINGENCIES

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

In July 2018, the Company entered into a 39 month lease for approximately 5,000 square feet of office space in 4 Houston Center in downtown Houston. Annual base rent is approximately $94,000 for the first 18 months, increasing to approximately $97,000 and $99,000 respectively during the remaining term of the lease. The lease term ended on September 30, 2021 and the Company entered into a twelve month lease that can be terminated with at least 30 days prior written notice. See Note 13 – Leases

The Company reached an agreement with a vendor in August 2018 for the settlement of approximately $1 million in debt. The vendor was paid $150,000 in cash, future cash payments of $7,500 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 September 30, 2021 and 2020, there is a fair value liability of approximately $721,000 and $786,000, respectively, which is included within Derivative Financial Instruments on the condensed balance sheet.

NOTE 13 – 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 financial statements for the adoption of ASC 842 effective on October 1, 2019:

The adoption of ASC 842 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 $16,430 cumulative effect of initially adopting ASC 842 as an adjustment to the opening balance of accumulated deficit.

At September 30, 2020 the right-of-use assets total $54,768 and the operating lease liabilities total $62,074, and at September 30, 2021 the right of use assets and operating lease liabilities were zero, respectively. The original lease term ended on September 30, 2021 and the new twelve month lease can be terminated with at least thirty days prior written notice.

NOTE 14 – SUBSEQUENT EVENTS

None 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to ensure that information required to be disclosed in the reports filed or submitted under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act are properly recorded, processed, summarized and reported within the time periods required by the Commission’s rules and forms.

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of these disclosure controls and procedures, as such term is defined in Exchange Act Rule 13a-15(e) and 15d-15(e), as of September 30, 2021. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2021, the end of the period covered by this Annual Report on Form 10-K.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. All control systems contain inherent limitations, no matter how well designed. As a result, our management acknowledges that its internal controls over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives.

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer evaluated the effectiveness of our internal control over financial reporting as of September 30, 2021. In making this assessment, management used the criteria established by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control – Integrated Framework (2013 Framework). Based on this evaluation, our management concluded that, as of September 30, 2021, our internal control over financial reporting was effective.

This Annual Report does not include an attestation report of our registered public accounting firm regarding our internal control over financial reporting due to an exemption established by the SEC for smaller reporting companies.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal controls over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

Not Applicable. 

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Identification of Directors and Executive Officers

Our executive officers and directors and their respective ages, positions and biographical information are set forth below.