Forward-looking Statements
The following discussion and analysis should be read in conjunction with our
accompanying unaudited condensed consolidated financial statements and the notes
to those financial statements included in Item 1 of this Quarterly Report on
Form 10-Q. The following discussion contains forward-looking statements within
the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934 (the "Exchange Act"). These forward-looking statements involve risks,
uncertainties and assumptions. If the risks or uncertainties materialize or the
assumptions prove incorrect, our results may differ materially from those
expressed or implied by such forward-looking statements and assumptions. All
statements other than statements of historical fact are statements that could be
deemed forward-looking statements, such as those statements that address
activities, events or developments that we expect, believe or anticipate will or
may occur in the future. These statements are based on certain assumptions and
analyses made by us in light of our experience and perception of historical
trends, current conditions, expected future developments and other factors we
believe are appropriate in the circumstances. Known material risks that may
affect our financial condition and results of operations are discussed in Item
1A, Risk Factors of our Annual Report on Form 10-K for the year ended September
30, 2021 and this Quarterly Report on Form 10-Q, Part II, Item 1A, Risk Factors,
and may be discussed or updated from time to time in subsequent reports filed
with the Securities and Exchange Commission. Readers are cautioned not to place
undue reliance on forward-looking statements, which speak only as of the date
hereof. We assume no obligation, nor do we intend to update these
forward-looking statements. Unless the context requires otherwise, references in
this Quarterly Report on Form 10-Q to "GulfSlope" "we," "us," "our" and the
"Company" refer to GulfSlope Energy, Inc.
Overview
GulfSlope Energy, Inc. is an independent crude oil and natural gas exploration
and production company whose interests are concentrated in the United States
Gulf of Mexico federal waters. We are a technically driven company and we use
our licensed 2.2 million acres of advanced three-dimensional ("3-D") seismic
data to identify, evaluate, and acquire assets with attractive economic
profiles. GulfSlope Energy commenced commercial operations in March 2013.
GulfSlope Energy was originally organized as a Utah corporation in 2004 and
became a Delaware corporation in 2012. We have focused our operations in the US
Gulf of Mexico because we believe this area provides us with favorable geologic
and economic conditions, including multiple reservoir formations, comprehensive
geologic databases, extensive infrastructure, relatively favorable royalty
regime, and an attractive acquisition market and because our management and
technical teams have significant experience and technical expertise in this
geologic province. Additionally, we licensed 2.2 million acres of advanced 3-D
seismic data, a significant portion of which has been enhanced by new,
state-of-the-art reprocessing and noise attenuation techniques including reverse
time migration depth imaging. We have used our broad regional seismic database
and our reprocessing efforts to generate and high-grade oil and natural gas
prospects. The use of our extensive seismic database, coupled with our ability,
knowledge, and expertise to effectively reprocess this seismic data, allows us
to further optimize our drilling operations and to effectively evaluate
acquisition and joint venture opportunities. We consistently assess our prospect
inventory in order to deploy capital as efficiently as possible. We have given
preference to areas with water depths of 450 feet or less where production
infrastructure already exists, which will allow for any discoveries to be
developed rapidly and cost effectively with the goal to reduce economic risk
while increasing returns
We have historically operated our business with working capital deficits and
these deficits have been funded by equity and debt investments and loans from
management. As of December 31, 2021, we had $0.9 million of cash on hand. The
Company estimates that it will need to raise a minimum of $10.0 million to meet
its obligations and planned expenditures through February 2023. The Company
plans to finance operations and planned expenditures through equity and/or debt
financings, farm-out agreements, and/or other transactions. There are no
assurances that financing will be available with acceptable terms, if at all.
Competitive Advantages
Experienced management. Our management team has a track record of finding,
developing and producing oil and natural gas in various hydrocarbon producing
basins including the US 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 US
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.
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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 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, expiring on June 30, 2022, and October 31, 2025. The Bureau of Ocean
Energy Management's ("BOEM") 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, to more precisely define the most optimal drillable location(s),
particularly for development of discoveries.
Acquisition Strategy
We are encouraged by a combination of macroeconomic factors that make the US
Gulf of Mexico an attractive target for producing property acquisitions.
Transaction activity has remained low despite the ongoing recovery of commodity
prices for oil and gas. Current holders of production are dominated by the
historically active major oil and gas companies and a smaller set of pure play
companies. Compelling motivations exist for many of these companies to divest,
as US Gulf of Mexico producing assets may no longer be core holdings, given the
competition for capital within their portfolios. Multiple existing holders of
production have stated their intention to exit the US Gulf of Mexico. GulfSlope
is a proven qualified operator in the US Gulf of Mexico and the management team
has broad and deep offshore experience.
Accordingly, we continue to identify and evaluate potential producing property
acquisitions in the offshore US Gulf of Mexico, taking advantage of our highly
specialized subsurface and engineering capabilities, knowledge, and expertise.
Any merger or acquisition is likely to be financed through the issuance of debt
and/or equity securities.
17
Drilling and other Exploratory and Development Strategies
Our plan has been to partner with other entities which could include oil and gas
companies and/or financial investors. Our goal is to diversify risk and minimize
capital exposure to exploration drilling costs. We expect a portion of our
exploration costs to be paid by our partners through these transactions, in
return for our previous investment in prospect generation and delivery of an
identified prospect on acreage we control. Such arrangements are a commonly
accepted industry method of proportionately recouping pre-drill cost outlays for
seismic, land, and associated interpretation expenses. We cannot assure you,
however, that we will be able to enter into any such arrangements on
satisfactory terms. In any drilling, we expect that our retained working
interest will be adjusted based upon factors such as geologic risk and well
cost. Early monetization of a discovered asset or a portion of a discovered
asset is an option for the Company as a means to fund development of additional
exploration projects as an alternative to potential equity or debt offerings.
However, if a reasonable value were not received from the market at the
discovery stage, then we may elect to retain (subject to lease terms) the
discovery asset undeveloped, until a reasonable offer is received in line with
our perceived market value, or we may elect to seek development partners on a
promoted basis in order to substantially reduce capital development
requirements.
Outlook
In the first quarter of 2020, the COVID-19 outbreak spread quickly across the
globe. Federal, state and local governments mobilized to implement containment
mechanisms and minimize impacts to their populations and economies. Various
containment measures, such as stay-at-home orders, closures of restaurants and
banning of group gatherings 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.
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 has been filed with the Bureau of Safety and
Environmental Enforcement and is pending approval. We are currently engaged in
the process of seeking additional partners for the drilling of the Tau #2 well.
The Company continues to be active in the evaluation of potential mergers and
producing property acquisitions that it deems to be attractive opportunities.
Any such merger or acquisition is likely to be financed through a combination of
debt and equity.
The Tau Prospect is located approximately six miles northeast of the Mahogany
Field, discovered in 1993. The Mahogany Field is recognized as the first
commercial discovery below allocthonous salt in the Gulf of Mexico. The Tau
Prospect is defined by mapping of 3D seismic reprocessed by RTM methods.
Drilling operations on the Tau subsalt prospect commenced in September 2018. The
wellbore 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. Planning is underway for a
redrill of the Tau prospect.
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.
18
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 received approximately $6.6 million in cash net to its 25% working
interest.
Significant Accounting Policies
The Company uses the full cost method of accounting for its oil and gas
exploration and development activities. Under the full cost method of
accounting, all costs associated with successful and unsuccessful exploration
and development activities are capitalized on a country-by-country basis into a
single cost center ("full cost pool"). Such costs include property acquisition
costs, geological and geophysical ("G&G") costs, carrying charges on
non-producing properties, costs of drilling both productive and non-productive
wells. Overhead costs, which includes employee compensation and benefits
including stock-based compensation, incurred that are directly related to
acquisition, exploration and development activities are capitalized. Interest
expense is capitalized related to unevaluated properties and wells in process
during the period in which the Company is incurring costs and expending
resources to get the properties ready for their intended purpose. For
significant investments in unproved properties and major development projects
that are not being currently depreciated, depleted, or amortized and on which
exploration or development activities are in progress, interest costs are
capitalized. Proceeds from property sales will generally be credited to the full
cost pool, with no gain or loss recognized, unless such a sale would
significantly alter the relationship between capitalized costs and the proved
reserves attributable to these costs. A significant alteration would typically
involve a sale of 25% or more of the proved reserves related to a single full
cost pool.
Proved properties are amortized on a country-by-country basis using the units of
production method ("UOP"), whereby capitalized costs are amortized over total
proved reserves. The amortization base in the UOP calculation includes the sum
of proved property, net of accumulated depreciation, depletion and amortization
("DD&A"), estimated future development costs (future costs to access and develop
proved reserves), and asset retirement costs, less related salvage value.
The costs of unproved properties and related capitalized costs (such as G&G
costs) are withheld from the amortization calculation until such time as they
are either developed or abandoned. Unproved properties and properties under
development are reviewed for impairment at least quarterly and are determined
through an evaluation considering, among other factors, seismic data,
requirements to relinquish acreage, drilling results, remaining time in the
commitment period, remaining capital plan, and political, economic, and market
conditions. In countries where proved reserves exist, exploratory drilling costs
associated with dry holes are transferred to proved properties immediately upon
determination that a well is dry and amortized accordingly. In countries where a
reserve base has not yet been established, impairments are charged to earnings.
At December 31, 2021, the Company continues to pursue the development of its
unproved properties and is actively finalizing the permitting of the Tau #2
well. As such, project economics continue to support cost incurred plus future
development therefore no impairment is required at December 31, 2021. However,
without the commencement of drilling the Tau #2 well, lease block Ship Shoal 336
will expire on June 30, 2022 unless an extension is granted for the lease block.
If drilling does not commence or an extension is not granted, then a portion of
the prospect cost will be required to be written off.
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 capitalized exploratory well costs
remain pending the outcome of exploration activities involving the drilling of
the Tau No. 2 well (twin well). Accordingly, these costs are included as
suspended well costs at December 31, 2021 and it is expected that a final
analysis will be completed in the next six months at which time the costs will
be transferred to the full cost pool upon final evaluation.
As of December 31, 2021, the Company's oil and gas properties consisted of wells
in process, capitalized exploration and acquisition costs for unproved
properties and no proved reserves.
19
Due to a combination of the COVID-19 pandemic and related pressures on the
global supply-demand balance for crude oil and related products, commodity
prices have been volatile. The Company has evaluated the effect of these factors
on its business and notes these factors have caused a delay in the plans for the
Company's 2022 drilling program. The Company continues to monitor the economic
environment and evaluate the impact on the business.
Property and equipment are carried at cost. We assess the carrying value of our
property and equipment for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable.
There has been no change to our critical accounting policies as included in our
annual report on Form 10-K as of September 30, 2021, which was filed with the
Securities and Exchange Commission on December 29, 2021.
Three Months Ended December 31, 2021, Compared to Three Months Ended December
31, 2020
There was no revenue during the three months ended December 31, 2021 and 2020.
General and administrative expenses were approximately $0.4 million for the
three months ended December 31, 2021, compared to approximately $0.4 million for
the three months ended December 31, 2020. Net interest expense was approximately
$138,000 for the three months ended December 31, 2021 as compared to
approximately $165,000 for the three months ended December 31, 2020 net of
approximately $1,000 of interest income. Gain on debt extinguishment was nil and
approximately $137,000 for the three months ended December 31, 2021and 2020,
respectively. Gain on derivative financial instruments was approximately $80,000
and $52,000 for the three months ended December 31, 2021 and 2020, respectively,
which was caused by the change in fair value of the underlying derivative
financial instruments.
Liquidity and Capital Resources
The Company has incurred accumulated losses for the period from inception to
December 31, 2021, of approximately $60.7 million, and has a negative working
capital of $12.6 million. For the three months ended December 31, 2021, the
Company has generated losses of approximately $0.5 million and net cash used in
operations of approximately $0.6 million. As of December 31, 2021, there was
$0.9 million of cash on hand. The Company estimates that it will need to raise a
minimum of $10 million to meet its obligations and planned expenditures through
February 2023. The $10 million is comprised primarily of capital project
expenditures as well as general and administrative expenses. It does not include
any amounts due under outstanding debt obligations and accrued interest, which
amounted to approximately $12.1 million as of December 31, 2021. The Company
plans to finance operations and planned expenditures through the issuance of
equity securities, debt financings, farm-out agreements, mergers or other
transactions. Our policy has been to periodically raise funds through the sale
of equity on a limited basis, to avoid undue dilution while at the early stages
of execution of our business plan. Short term needs have been historically
funded through loans from executive management. There are no assurances that
financing will be available with acceptable terms, if at all. If the Company is
not successful in obtaining financing, operations would need to be curtailed or
ceased. The accompanying financial statements do not include any adjustments
that might result from the outcome of this uncertainty.
For the three months ended December 31, 2021, the Company used approximately
$0.6 million of net cash used in operating activities, compared with
approximately $0.5 million of net cash used in operating activities for the
three months ended December 31, 2020. For the three months ended December 31,
2021, approximately $0.02 million of cash was used in investing activities
compared with approximately $0.1 million of cash provided by investing
activities for the three months ended December 31, 2020. For the three months
ended December 31, 2021, the Company used nil of net cash in financing
activities compared with approximately $0.3 million used in financing activities
for the three months ended December 31, 2020 to pay notes payable.
The Company will need to raise additional funds to cover planned expenditures,
as well as any additional, unexpected expenditures that we may encounter. Future
equity financings may be dilutive to our stockholders. Alternative forms of
future financings may include preferences or rights superior to our common
stock. Debt financings may involve a pledge of assets and will rank senior to
our common stock. We have historically financed our operations through private
equity and debt financings. We do not have any credit or equity facilities
available with financial institutions, stockholders or third-party investors,
and will continue to rely on best efforts financings. The failure to raise
sufficient capital could cause us to cease operations, or the Company would need
to sell assets or consider alternative plans up to and including restructuring.
Off-Balance Sheet Arrangements
None.
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