PART I
Overview
We
previously operated under the corporate name of TetriDyn Solutions,
Inc. (“TetriDyn”). On March 10, 2017, TetriDyn entered
into an Agreement and Plan of Merger (the “Merger
Agreement”) with Ocean Thermal Energy Corporation
(“OTE”), a Nevada corporation that used its proprietary
technology to develop, build, own, and operate renewable energy
systems, primarily in the Eastern and Western Caribbean Islands. On
May 9, 2017, TetriDyn consummated the acquisition of all
outstanding equity interests of OTE pursuant to the terms of the
Merger Agreement, with a newly created Delaware corporation that is
wholly owned by TetriDyn (“TetriDyn Merger Sub”),
merging with and into OTE (the “Merger”) and OTE
continuing as the surviving corporation and a wholly owned
subsidiary of TetriDyn. Effective upon the consummation of the
Merger, the OTE stock issued and outstanding or existing
immediately prior to the closing was converted into the right to
receive newly issued shares of TetriDyn common stock. As a result
of the Merger, TetriDyn succeeded to the business and operations of
OTE. In connection with the consummation of the Merger and upon the
consent of the holders of a majority of the outstanding common
shares, TetriDyn filed with the Nevada Secretary of State an
amendment to its articles of incorporation changing its name to
“Ocean Thermal Energy Corporation.”
Our Business
We
develop projects for renewable power generation, desalinated water
production, and air conditioning using proprietary intellectual
property designed and developed by our own experienced
oceanographers, engineers, and marine scientists. Plants using our
technologies are designed to extract energy from the temperature
difference between warm surface ocean water and cold deep seawater
at a depth of approximately 3,000 feet. We believe these
technologies provide practical solutions to mankind’s
fundamental needs for sustainable, affordable energy; desalinated
water for domestic, agricultural, and aquaculture uses; and
cooling, all without the use of fossil fuels.
●
Ocean Thermal
Electrical Conversion, known in the industry as “OTEC,”
power plants are designed to produce electricity. In addition, some
of the seawater running through an OTEC plant can be desalinated
efficiently, producing fresh water for agriculture and human
consumption.
●
Seawater Air
Conditioning, known in its industry as SWAC, plants are designed to
use cold water from ocean depths to provide air conditioning for
large commercial buildings or other facilities. This same
technology can also use deep cold water from lakes, known as
Lakewater Air Conditioning or LWAC.
Both
OTEC and SWAC/LWAC systems can be engineered to produce desalinated
water for potable, agricultural, and fish farming/aquaculture
uses.
Many applications of technologies based on ocean
temperature differences between surface and deep seawater have been
developed at the Natural Energy Laboratory of Hawaii Authority, or
NELHA, test facility (http://nelha.hawaii.gov), including
applications for desalinated seawater, fish-farming, and
agriculture. Note: All URL addresses in this report are inactive
textual references only. We believe our proprietary advances to
existing technologies developed by others in the industry enhance
their commercialization for the plants we propose to develop.
We
have recruited a scientific and engineering team that includes
oceanographers, engineers, and marine scientists who have worked
for a variety of organizations since the 1970s on several systems
based on extracting the energy from the temperature differences
between surface and deep seawater, including projects by NELHA, the
Argonne National Laboratory (http://www.anl.gov), and others. Our
executive team members have complementary experience in leading
engineering and technical companies and projects from start-up to
commercialization.
In
addition, we expect to use our technology in the development of an
OTEC EcoVillage, which should add significant value to our
business. We will facilitate the development of sustainable living
communities by creating an ecologically sustainable “OTEC
EcoVillage” powered by 100% fossil-fuel free electricity. In
the development, buildings will be cooled by energy-efficient and
chemical-free systems, and water for drinking, aquaculture, and
agriculture will be produced onsite. The OTEC EcoVillage project
consists, in part, of an OTEC plant that will provide all power and
water to about 400 residences, a hotel, and a shopping center, as
well as models of sustainable agriculture, food production, and
other economic developments. Each sale of luxury EcoVillage
residences will support the development of environmentally
responsible affordable communities currently in development in
tropical and subtropical regions of the world. We believe our OTEC
EcoVillage will be the first development in the world offering a
net-zero carbon footprint. This will be our pilot project, launched
to prove the viability of OTEC technology to provide affordable
renewable energy for entire communities. We believe this project
could be highly profitable and generate significant value for our
shareholders. The U.S. Virgin Islands’ Public Service
Commission has granted regulatory approval to us for an OTEC plant.
The specific plots of land for the site have been identified and
inspected, and negotiations have been entered into with agents for
the owners. A meeting has been held with the Chief Legal Counsel to
the Governor of the U.S. Virgin Islands to further the support for
the project. Local consultants have been engaged, and a permitting
plan is being finalized based on the draft of the master plan for
the entire development.
Our Vision
Our
vision is to bring our technologies to tropical and subtropical
regions of the world where about three billion people live. Our
market includes 68 countries and 29 territories with suitable sea
depth, shore configuration, and market need; we plan to be the
first company in the world to design and build a commercial-scale
OTEC plant and, to that end, have several projects in the planning
stages. Our initial markets and potential projects include several
U.S. Department of Defense bases situated in the Asia Pacific and
other regions where energy independence is crucial. Currently, we
have projects in the planning and development stages in Puerto Rico
and the U.S. Virgin Islands.
Our Technology
OTEC
is a self-sustaining energy source, with no supplemental power
required to generate continuous (24/7) electricity. It works by
converting heat from the sun, which has warmed ocean surface water,
into electric power, and then completing the process by cooling the
plant with cold water from deep in the ocean. The cold water can
also be used for very efficient air conditioning and desalinated to
produce fresh water. OTEC has worked in test settings where there
exists a natural temperature gradient of 20 degrees Celsius or
greater in the ocean. We believe OTEC can deliver sustainable
electricity in tropical and subtropical regions of the world at
rates approximately 20-40% lower than typical costs for electricity
produced by fossil fuels in those markets.
Further, we believe
that a small, commercial OTEC plant could offer competitive returns
even in a market where the cost of electricity is as low as $0.30
per kilowatt-hour, or kWh. The Caribbean depends on imported oil
for approximately 90% of its energy needs. The electricity prices
in the Caribbean are extremely high, with an average of $0.34 per
kWh and as high as $0.50 per kWh, which is nearly four times the
price paid in the United States, according to a 2017 renewable
energy report, when oil prices were lower. For the U.S. Virgin
Islands, the Water and Power Authority of the Virgin Islands
reported that as of February 1, 2019, the average price for
electricity for commercial customers was nearly $0.4374 per kWh. We
believe that we have an opportunity to offer base-load energy (the
amount of energy required to meet minimum requirements) pricing
that is better than our customer’s next best alternative in
the markets where electricity costs are $0.30 or more per
kWh.
Technology
advancements have significantly reduced the capital costs of OTEC
to make it competitive compared to traditional energy sources.
Technology improvements include larger diameter seawater pipes
manufactured with improved materials, increased pumping
capabilities from OTEC depths, better understanding of material
requirements in the deep ocean environment, more experience in deep
water pipeline and cable installation techniques, and more accurate
sea bottom mapping technology, which is required for platform
positioning and pipe installation. The cold-water pipes at a
demonstration site in Hawaii have been in continuous operation for
more than 20 years, and the technology has improved significantly
since the Hawaiian installation.
We
estimate that a small OTEC plant that delivers 13 megawatts (MWs)
per hour for 30 years would currently cost approximately $350
million. This is the plant size that we typically propose for our
initial target markets to meet 20% or more of their current demand
for electricity and a large portion of their need for fresh
drinking water and agricultural water. OTEC has been proven in test
settings at NELHA, where a Department of Energy-sponsored OTEC
plant operated successfully throughout the 1990s to produce
continuous, affordable electricity from the sea without the use of
fossil fuels. Spin-off technologies of desalination and seawater
cooling, developed from the OTEC plant at NELHA, have also become
economically and technically feasible.
Finally,
we believe the decreasing supply and increasing cost of
fossil-fuel-based energy has intensified the search for renewable
alternatives. We further believe that renewable energy sources,
although traditionally more expensive than comparable fossil-fuel
plants, have many advantages, including increased national energy
security, decreased carbon emissions, and compliance with renewable
energy mandates and air quality regulations. We believe these
market forces will continue and potentially increase. In remote
islands where shipping costs and limited economies of scale
substantially increase fossil-fuel-based energy, renewable energy
sources may be attractive. Many islands contain strategic military
bases with high-energy demands that we believe would greatly
benefit from a less expensive, reliable source of energy that is
produced locally, such as OTEC.
SWAC/LWAC
is a process that uses cold water from locations such as the ocean
or deep lakes to provide the cooling capacity to replace
traditional electrical chillers in an air conditioning system.
SWAC/LWAC applications can reduce the energy consumption of a
traditional air-conditioning system by as much as 90%. Even when
the capital cost amortization of building a typically sized
SWAC/LWAC system providing 9,800 tons of cooling ($140-$150
million) are taken into account, SWAC/LWAC can save the customer
approximately 25-40% when compared to conventional systems—we
estimate savings can be as high as 50% in locations where air
temperatures and electricity costs are high. Cooling systems using
seawater or groundwater for large commercial structures are in use
at numerous locations developed and operated by others worldwide,
including Heathrow Airport, UK; Finland (Google Data Center);
Cornell University, NY; Stockholm, Sweden; and the City of Toronto,
Canada.
How Our Technology Works
OTEC
uses the natural temperature difference between cooler deep ocean
water at a depth of approximately 3,000 feet and warmer shallow or
surface water to create energy. An OTEC plant project involves
installing about 6.0 feet diameter, deep-ocean intake pipes (which
can readily be purchased), together with surface water pipes, to
bring seawater onshore. OTEC uses a heat pump cycle to generate
power. In this application, an array of heat exchangers transfer
the warm ocean surface water as an energy source to vaporize a
liquid in a closed loop, driving a turbine, which in turn drives a
generator to produce electricity. The cold deep ocean water
provides the required temperature to condense vapor back into a
liquid, thus completing the thermodynamic cycle, which is
constantly and continuously repeated. The working fluid is
typically ammonia, as it has a low boiling point. Its high hydrogen
density makes ammonia a very promising green energy storage and
distribution media. Among practical fuels, ammonia has the highest
hydrogen density, including hydrogen itself, in either its low
temperature, or cryogenic, and compressed forms. Moreover, since
the ammonia molecule is free of carbon atoms (unlike many other
practical fuels), combustion of ammonia does not result in any
carbon dioxide emissions. The fact that ammonia is already a widely
produced and used commodity with well-established distribution and
handling procedures allows for its use as an alternative fuel. This
same general principle is used in steam turbines, internal
combustion engines, and, in reverse, refrigerators. Rather than
using heat energy from the burning of fossil fuels, OTEC power
draws on temperature differences of the ocean caused by the
sun’s warming of the ocean’s surface, providing an
unlimited and free source of energy.
OTEC
and SWAC/LWAC infrastructure offers a modular design that
facilitates adding components to satisfy customer requirements and
access to a sufficient supply of cold water. These components
include reverse-osmosis desalination plants to produce drinkable
water, bottling plants to commercialize the drinkable water, and
off-take solutions for aquaculture uses (such as fish farms), which
benefit from the enhanced nutrient content of deep ocean water. A
further advantage of a modular design is that, depending on the
patterns of electricity demand and output of the OTEC plant, a
desalination plant can be run using the excess electricity
capacity.
Currently,
OTEC requires a minimum temperature difference of approximately 20
degrees Celsius to operate, with each degree greater than this
increasing output by approximately 10-15%. OTEC has potential
applications in tropical and subtropical zones and is particularly
well suited for tropical islands and coastal areas with proximate
access to both cold deep water and warm surface water. These
communities are typically subject to high and fluctuating energy
costs ranging from $0.28-$0.75 per kWh, as they rely on importing
fossil fuels for power generation. Data from the National Renewable
Energy Laboratory of the U.S. Department of Energy website
indicated that at least 68 countries and 29 territories around the
globe appear to meet these criteria.
The
world’s largest OTEC power plant to date is operational at
the NELHA facility in Hawaii and is connected to the electrical
grid. It provides base-load electricity produced by OTEC to about
150 homes. Around the world, a couple of other successful
developmental and experimental plants have been built, and the U.S.
National Oceanic and Atmospheric Administration, or NOAA, has
stated that: “The qualitative analysis of the technical
readiness of OTEC by experts at this workshop suggest that a <10
MWe floating, closed-cycle OTEC facility is technically feasible
using current design, manufacturing, deployment techniques and
materials”
(https://coast.noaa.gov/data/czm/media/otec_nov09_tech.pdf). We
believe that we have sufficient skill and knowledge to now
commercialize 5-MW to 30-MW land-based OTEC plants, using
off-the-shelf components, including the cold-water
piping.
SWAC/LWAC
is a significantly more cost-effective and environmentally friendly
way to implement air-conditioning using cold water sourced from
lakes or, analogous with OTEC, deep ocean water, rather than from
an electric chiller. Comparing Federal Energy Management Program
engineering efficiency requirements of approximately 0.94 kilowatts
of electricity per ton of cooling capacity with our own engineering
estimates of 0.09 kilowatts of electricity per ton of cooling
capacity, as calculated by DCO Energy, our engineering,
procurement, and construction partner, we estimate that SWAC/LWAC
systems can reduce electricity consumption by up to 80-90% over
conventional systems. Therefore, we believe energy reductions may
make SWAC/LWAC systems well-suited for large structures, such as
office complexes, medical centers, resorts, data centers, airports,
and shopping malls. We believe that other SWAC/LWAC plants we may
develop will likely achieve similar efficiencies. There are
examples of proven successful SWAC/LWAC systems in use, including a
large 79,000-ton system used to cool buildings in the downtown area
of the City of Toronto, Canada; a SWAC/LWAC system in
Google’s data center in Finland that uses waters from the
Baltic Sea to keep servers cool; and a system with more than 18,000
tons of cooling in operation at Cornell University, Ithaca, New
York. On January 10, 2018, William S. (Lanny) Joyce joined our
board of advisors. Mr. Joyce was the Director of Utilities and
Energy Management in the Energy and Sustainability Department at
Cornell University, Ithaca, New York. Mr. Joyce initiated and was
project manager for innovative and award-winning Cornell University
LWAC project completed in 2000 that provides all of the chilled
water production on the central campus utilizing a renewable
resource and 86% less energy.
OTEC Versus Other Energy Sources
The
construction costs of power plants using any technology are much
higher in remote locations, such as tropical islands, than on the
mainland of the United States, principally due to the need to
transport materials, components, and other construction supplies
and labor not available locally. There are also considerations that
make those other technologies less attractive in those areas. We
believe the consistency of OTEC during its life provides clear
advantages over other power-generation technology in the tropical
and subtropical markets, because its base-load power (available at
all times and not subject to fluctuations throughout the day) is an
important asset to the small transmission grid, which is typical in
these regions.
Combined-cycle
natural gas plants typically need to be capable of generating
several hundred MWs to attain the lower-cost, per-kilowatt
installed values that make the plant economically feasible.
Tropical locations do not have large enough grids and market demand
to make that plant size reasonable. Further, tropical locations
frequently do not have domestic fuel supplies, requiring fuel to be
imported. In order to import natural gas, it must be liquefied for
shipment and then vaporized at the location. There are initial cost
and public safety concerns with such facilities. In addition,
gas-fired plants emit undesirable nitrogen oxide, carbon dioxide,
and volatile organic compounds.
Solar
applications continue to increase as the cost and effectiveness of
photovoltaic panels improve. However, we estimate that the cost to
install solar panels in tropical regions remains high. Beyond the
issues with shipping and labor costs that all construction must
overcome, the design and building code requirements are tougher in
storm-prone areas, which are subject to potential wind damage from
hurricanes, earthquakes, and typhoons, than are typically
encountered in mainland nontropical installations. Support
structures must be more substantial in order to hold the solar
panels in place in case of hurricane-force winds. Solar power, like
wind power, places substantial stress on an electrical grid. Since
the input of both of these sources is subject to weather
conditions, they cannot be considered reliable suppliers of power,
and back-up capacity is necessary. Further, instantaneous changes
in output due to sporadic cloud cover create transient power flow
to the grid and difficulties in maintaining proper voltages and
stability. OTEC is a stabilizing source to the grid, providing
constant and predictable power, and has no emissions. The ability
of OTEC to provide constant, continuous power is a large benefit as
compared to any of the other renewable options
available.
Our
estimated price for OTEC-generated power of approximately $0.30 per
kWh under current economic conditions, which can be as low as $0.18
net per kWh with maximum efficiency and revenue from water
production, is also constant both throughout the year and over a
plant’s life. OTEC’s power price, determined almost
entirely by the amortization of its initial cost, is a protection
against inflation and rising interest rates, which greatly affect
coal and oil. Customers in our target markets currently pay from
$0.35 to as high as $0.60 per kWh for power from coal and
oil-fueled power plants. However, imported fuels are subject to
price volatility, which has a direct impact on the cost of
electricity and adds operating risk during the life of a plant. The
fuel handling to allow for the shipping, storage, and local
transport is expensive, a potential source of damaging fuel spills
and a basis for environmental concerns. Fossil-fuel plants create
pollution, emit carbon dioxide, and are visually unappealing, which
is of particular concern in tropical areas renowned for their
clear, pristine air and beauty. We project OTEC can save these
markets up to 40%, compared to their current electrical costs, and
when revenues from fresh drinking water, aquaculture, and
agriculture production are considered, the justification is even
more compelling.
Overview of the Market and the Feasibility of OTEC in Current
Market Conditions
We
believe that OTEC is now an economically, technologically, and
environmentally competitive power source, especially for developing
or emerging countries in certain tropical and subtropical regions
contiguous to oceans. Our natural target markets are communities in
countries around the Caribbean, Asia, and the Pacific. These
locations are typically characterized by limited infrastructure,
high-energy costs, mostly imported or expensively generated
electricity, and frequently with significant fresh water and food
shortages. These are serious limitations on economic development,
which we believe our OTEC technology can address.
Data presented to the Sustainable Use of Oceans in
the Context of the Green Economy and the Eradication of
Poverty workshop in Monaco in
2011 by Whitney Blanchard of the Office of Ocean and Coastal
Resource Management, National Oceanic and Atmospheric
Administration, show that at least 98 nations and territories using
an estimated five terawatts of potential OTEC net power are
candidates for OTEC-power systems. Blanchard specifically notes
that Hawaii, Guam, Florida, Puerto Rico, and the U.S. Virgin
Islands are suitable for OTEC.
Over
the past 15 years, there have been substantial changes in many
areas that have now made the commercialization of OTEC a reality.
First and foremost is the price of oil, which until 2006/2007 had
been relatively inexpensive.
Recent
oil prices have been volatile, owing in large part to political
instability in the Middle East and elsewhere. OPEC crude oil prices
averaged $64.05 in 2019, with a peak of over $74. Over the last
decade oil prices have varied from a low of $26 to a peak of over
$111.
Facts
like these have resulted in increased attention and interest in
OTEC in the commercial sector and among candidates. With OTEC
power, customers can decouple the price of electricity from the
price of oil.
The
International Energy Agency’s World Energy Outlook expects
liquid natural gas export capacity to grow rapidly in the short
term, with major new sources of supply coming mostly from Australia
and the United States.
Liquid
natural gas prices have collapsed, in part because demand is
turning out to be weaker than some previously anticipated.
Additionally, many rules and regulations are in effect to mitigate
the environmental issues associated with liquid natural gas
extraction, transportation, and storage, adding significant
costs.
According to the
U.S. Environmental Protection Agency, in the United States, nearly
29% of 2017 greenhouse gas emissions was generated primarily
from burning fossil fuel for our cars, trucks, ships, trains, and
planes. Over 90% of the fuel used for transportation is
petroleum-based, which includes gasoline and diesel. The electric
power sector accounted for 28% of total greenhouse gas emissions in
2017.
According to the
U.S. Environmental Protection Agency: “Global carbon
emissions from fossil fuels have significantly increased since
1900. Since 1970, CO2 emissions have increased by about 90%, with
emissions from fossil fuel combustion and industrial processes
contributing about 78% of the total greenhouse gas emissions
increase from 1970 to 2011.”
Greenhouse gas
emissions from electricity have increased between 1990 and 2007 as
electricity demand grew and fossil fuels remained the dominant
source for generations. Fossil-fuel-fired power plants are a
significant source of domestic carbon dioxide emissions, the
primary cause of global warming. To generate electricity,
fossil-fuel-fired power plants use natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel derived from such
materials. Along with the increasing use of renewable energy, the
greenhouse emissions from power generation has decreased since
2007, approaching the 1990 levels.
The
U.S. Energy Information Administration states that renewable energy
plays an important role in reducing greenhouse gas emissions. Using
renewable energy can reduce the use of fossil fuels, which are
major sources of U.S. carbon dioxide emissions. The
consumption of biofuels and other non-hydroelectric renewable
energy sources more than doubled from 2000 to 2017, mainly because
of state and federal government requirements and incentives to use
renewable energy. The U.S. Energy Information Administration
projects that U.S. renewable energy consumption will continue to
increase through 2050.
People
in many countries today, including the United States, are concerned
with environmental issues caused by fossil-fuel-generated power.
Gallup surveys find public acceptance of climate change is rising.
The number of Americans that the organization terms
“concerned believers” on climate change has risen from
37% in 2015 to 47% in 2016 and to 50% in the spring of 2017. NASA
has long confirmed the scientific consensus that the Earth’s
climate is warming.
The
international concern about the harmful effects of climate change
led to the negotiation of the Paris Agreement in December 2015 as
the culmination of the 2015 United Nations Climate Change
Conference. The agreement provides for members to reduce their
carbon output as soon as possible and to do their best to keep
global warming to no more than two degrees Celsius, or 3.6 degrees
Fahrenheit. In order to achieve the desired results, there would
have to be a worldwide reduction in emissions from fossil fuels and
a shift to renewable resources.
Global
acceptance of man’s influence on climate change may also
contribute to a shift in the demand for OTEC. As evidenced by the
Paris Agreement reached in December 2015 to combat climate change,
195 nations expressly recognized that conventional fossil-fuel
powered energy technologies affect global climate change and the
need to embrace a sustainable future in energy and water. Low-lying
coastal countries (sometimes referred to as small island developing
states) that tend to share similar sustainable development
challenges, including small but growing populations, limited
resources, remoteness, susceptibility to natural disasters,
vulnerability to external shocks, excessive dependence on
international trade, and fragile environments, have embraced this
recognition and are keenly aware that they are on the frontline of
early impact of sea level rise and are aggressively trying to
embrace sustainable-energy alternatives. This is a major driving
force for OTEC in primary early markets.
President Donald
Trump has pulled the United States out of the Paris accord, but
other Americans are standing with the world to help fight the
‘existential crisis’ of global warming, A coalition of
14 U.S. states, including California and New York, have said they
are on track to meet the U.S. target of a 26-28% reduction in
greenhouse gas emissions by 2025, compared to 2005
level.
In
November 2017, the United Nations Climate Conference opened in
Bonn, Germany, with the aim of a greater ambition for climate
action, as the world body’s weather agency issued a stark
warning that 2017 was set to be among the three hottest years on
record.
We
believe the ongoing concerns about environmental issues and the
price instability of fossil-fuel prices are motivation for
increased commercial interest in OTEC, renewed activity in the
commercial sector, and increased interest among communities and
agencies that recognize the potential benefits of this technology,
including the U.S. Department of Defense and U.S. Department of the
Interior territories.
Several
large companies have used their OTEC technology experience to
introduce OTEC systems worldwide, supporting the argument that the
technology is now at the point where it can be introduced at a
commercial level:
●
In June 2014, the
French companies, Akuo Energy and DCNS (now Naval Energies), were
funded to construct and install a number of OTEC plants adding up
to 16 MWs of power generation outside the coastline of Martinique
in the Caribbean. This is by far the biggest OTEC project announced
to date, and the European Union has allocated €72 million
(about $78 million at current exchange rates) for this purpose.
DCNS (now Naval Energies) is our teaming partner for potential
projects in the Caribbean.
●
Since early 2014,
we have been working with several industrialized and developing
countries, including U.S. Virgin Islands, The Bahamas, Cayman
Islands, and others, and investigating suitable OTEC sites,
infrastructural solutions, and funding opportunities.
●
Two nongovernmental
organizations promoting OTEC have been created: OTEC Foundation
(based in The Netherlands) and OTEC Africa (based in
Sweden).
●
New technological
advances for larger and more robust deep seawater pipes and more
efficient and cost-effective heat exchangers, pumps, and other
components have, in our opinion, further improved the economics for
OTEC.
●
Many countries,
including a large number of Caribbean nations, now have renewable
energy standards and are looking at ways to reduce their carbon
footprints, decouple the price of electricity from the volatile
price of oil, and increase energy security. Along with these
countries, we are aware that Hawaii, U.S. territories, and the U.S.
Department of Defense are looking at OTEC as a possible source of
renewable energy and water for drinking, fish farming, and
agriculture.
●
The NELHA
demonstration OTEC plant in Hawaii is producing 100 kilowatts of
sustainable, continuous electricity annually and is powering a
neighborhood of 120 homes. A potential next phase for OTEC
development at NELHA is being considered by an international
consortium under 2010 Okinawa-Hawaii clean energy agreement, which
was extended in 2015.
●
BARDOT Group, a
French SME specialized in subsea engineering and equipment
manufacturing for offshore energy, stated it has signed a contract
for the first commercial OTEC system to be installed in an
eco-resort in Maldives.
Recent
international political instability in fossil-fuel-producing
regions and oil price volatility have exposed the criticality of
energy security and independence for all countries. The need to
have a tighter control of domestic energy requirements is a matter
of increasing international concern. Continued reliance on other
countries (particularly those in oil-producing regions) is no
longer a favorable option. We believe these considerations will
continue to drive renewable research and commercialization efforts
that promote technologies with global potential to replace
fossil-fuel-based energy systems and benefit from base-load
capabilities like OTEC.
Our
current management team has led the development of the business
since 2010 and has established a pipeline of potential projects,
which include one signed 20-year energy services agreement, and six
signed memoranda of understanding. The projects under these
agreements included the designs for OTEC, SWAC/LWAC, or a
combination of both plants in the U.S. Virgin Islands, Bahamas, an
island in the Indian Ocean, and in East Africa. The Public Services
Commission of the U.S. Virgin Islands has approved our application
to be a “qualified facility” and build a 15MW OTEC
plant on the island of St. Croix. In addition to the OTEC plant, we
are negotiating additional opportunities to supply potable water to
the U.S. Virgin Islands government.
We
are discussing both OTEC and SWAC/LWAC projects with the U.S.
Department of Agriculture and the Secretary of Commerce for Puerto
Rico. Currently, two projects are in the planning and discussion
phase:
●
EcoVillage
powered by an OTEC plant for Puerto Rico; and
●
Eco Village powered
by an OTEC plant for the U.S. Virgin Islands.
We
have provided a detailed study and designs for OTEC and/or
SWAC/LWAC to:
●
The U.S. Department
of Agriculture for a combined OTEC/SWAC/LWAC plant for
Guam.
●
The Legislature of
the U.S. Virgin Islands for an OTEC plant for the island of St.
Croix.
In
light of the foregoing, we believe that it is now appropriate to
seek additional funding to further progress and build our
engineering and technical teams, develop our intellectual property,
file patents for several OTEC technical systems, and advance our
current opportunities to support our growth strategy.
Our Competition
We
compete in the development, construction, and operation of OTEC and
SWAC/LWAC plants with other operators that develop similar
facilities powered by other energy sources, primarily oil, natural
gas, nuclear energy, and solar power. These traditional energy
sources have well-established infrastructures for production,
delivery, and supply, with well-known commercial terms. In
developing our OTEC and SWAC/LWAC plants, we will need to satisfy
our customers that these technologies are sound and economical,
which may be a challenge until and unless we have an established
successful operating history. The energy industry is dominated by
an array of companies of all sizes that have proven technologies
and well-established fuel sources from a number of
suppliers.
We expect that we will encounter increasing
competition for OTEC and SWAC/LWAC plants. Other firms with greater
financial and technical resources are focusing on commercialization
of these technologies. This includes, for example, Akuo Energy and
DCNS (now Naval Energies) and Bardot Energy of Paris, France. Our
competitors may benefit from collaborative relationships with
countries, including a large number of Caribbean nations, that now
have renewable-energy standards and are looking at ways to reduce
their carbon footprints, decouple the price of electricity from the
volatile price of oil, and increase energy security. Other
competitors may have advantageous relationships with authorities
such as Hawaii, U.S. territories, and the U.S. Department of
Defense, which are looking at OTEC as a possible source of
renewable energy and water for drinking, fish farming, and
agriculture.
We
cannot assure that we will be able to compete effectively as the
industry grows and becomes more established and as OTEC and
SWAC/LWAC plants become more accepted as viable and economic energy
solutions.
We
believe competition in this industry is and will be based on
technical soundness and viability, the economics of plant outputs
as compared to other energy sources, developmental reputation and
expertise, financial capability, and ability to develop
relationships with potential customers. All of these factors are
outside our control.
Our Operational Strategy and Economic Models
We
have developed economic models of costs and potential revenue
structures that we will seek to implement as we develop OTEC and
SWAC/LWAC projects.
OTEC Projects
The
estimated construction costs for a 20-MW plant are approximately
$445 million with hard costs of approximately $301 million for the
power system and platform construction and piping, which make up
68% of the total. The remaining 32% consists of other construction
costs and the deployment of the cold water pipe and soft costs of
approximately $144 million for design, permits and licensing,
environmental impact assessment, bathymetry, contractor fees, and
insurance.
Once
operational, the capacity factor, which is the projected percent of
time that a power system will be fully operational, considering
maintenance, inspections, and estimated unforeseen events, is
expected to be 95% annually. This factor is used in our financial
calculations, which means the plant will not be generating revenue
for 5% of the year. Most fossil-fuel plants have capacity factors
around 90%, as a result of the major maintenance for
high-temperature boilers, fossil-fuel feed in systems, safety
inspections, cleaning, etc. The normal maintenance cycle for the
pumps, turbine, and generators used in the OTEC plant is typically
every five years. This includes the cleaning of the heat exchangers
and installation of new seals.
We
anticipate that project returns will be comprised of two
components: First, as the project developer, we will seek a
lump-sum payment as a development fee at the time of closing the
project financing for each project. These payments will be
allocated toward reimbursement of development costs and perhaps a
financial return at the early stage of each project. The
development fee will vary, but initially we will seek a fee of
approximately 3% of the project cost, payable upon closing the
project financing. Second, we will retain a percentage of equity in
the project, with a goal to retain a minimum of 51% of the equity
in any OTEC project in order to participate in operating
revenues.
We
will seek revenue from OTEC plants from contract pricing charged on
an energy-only price per kWh or on the basis of a generating
capacity payment priced per kilowatt per month and an energy usage
price per kWh. In many of the countries of the world where we
intend to build OTEC and SWAC/LWAC plants, potable water is in
short supply. In some locations, water is considered the more
important commodity. Depending on the part of the world in which
the plant is built, in addition to revenue from power generation,
supplying water for drinking, fish farming, and agriculture would
significantly increase plant revenue.
We
cannot assure that we can maintain the revenue points noted above,
that any fees received will offset development costs incurred to
date, or that any operating plant will generate
revenue.
SWAC/LWAC Projects
The
estimated construction costs for a SWAC/LWAC plant are
approximately $150 million with hard costs of approximately $91
million for piping and installation, which make up 60% of the
total. The remaining 40% consists of the pump house, central
utility plant (CUP), mechanical and engineering equipment, design,
and other contingency costs and soft costs of approximately $59
million for the CUP license, permits, environmental impact
assessment, bathymetry, and insurance.
Under
our economic model, we will seek revenue at two stages of the
project. First, as the project developer, we will seek a lump-sum
payment of a development fee equal to approximately 3% of the
project cost at the time of closing the project financing for each
project. These payments would provide us with income at the early
stage of each project. If we are able to negotiate a development
fee, we estimate that it will vary, but typically will be in the
$2,500,000-$3,500,000 range. The second component of project
returns is based upon the percentage of equity we will retain in
the project.
SWAC/LWAC
contract revenue will be based typically on three
charges:
●
Fixed
Price–this is based upon the capital costs of the project
paid over the term of the debt and with the intention of covering
the costs of debt.
●
Operation and
Maintenance–this payment covers the cost of the labor and
fixed overhead needed to run the SWAC/LWAC system, as well as any
traditional chiller plant operating to fulfill back-up or peak-load
requirements.
●
Chilled Water
Payment–this is a variable charge based on the actual chilled
water use and chilled water generated both by the SWAC/LWAC and
conventional system at the agreed upon conversion factors of
kilowatt/ton and current electricity costs in U.S. dollars per
kWh.
We
plan to structure project financing with the goal of retaining 100%
of the equity in any SWAC/LWAC project. We cannot assure that we
will recover project development costs or realize a financial
return over the life of the project.
Our Project Timeline
We
have not designed, constructed, and placed into operation any OTEC
or SWAC/LWAC plants. However, based on our planning process and
early development experience to date, we estimate that it will take
approximately two years or more, depending on local conditions,
including regulatory and permitting requirements, to take a project
from a preliminary memorandum of understanding with a potential
power or other product purchaser to completion and commencement of
operation.
Our Strategic Relationships
We
have strategic relationships with each of the following parties for
potential plant construction, design and architectural services,
and the funding of projects.
●
DCO Energy, LLC,
Mays Landing, New Jersey, is an American energy development company
specializing in the development, engineering, construction,
start-up, commissioning, operation, maintenance and management, as
well as ownership of central energy centers, renewable energy
projects, and combined heat, chilling, and power-production
facilities. DCO Energy was formed in 2000 and has independently
developed and/or operated energy producing facilities of
approximately 275 MW of electric, 400 MMBtu/hr of heat recovery,
1,500 MMBtu/hr of boiler capacity, and 130,000 tons of chilled
water capacity, totaling over $1 billion of assets. DCO Energy
provides financing, engineering and design, construction
management, start-up and commissioning resources, and long-term
operating and maintenance services for its own projects as well as
third-party clients.
●
Naval Energies
(f/k/a DCNS) Paris, France, is a French naval defense company and
one of Europe’s largest ship builders. In 2019, it employed
15,168 people and generated annual revenues of around €3.7
billion
(https://www.naval-group.com/en/group/en-profil/en-chiffres-cles/).
In 2009, Naval Energies set up an incubator dedicated to marine
renewable energies and has stated its intention to be a leader in
this market, which includes marine turbines, floating wind
turbines, OTEC, and tidal stream turbines.
●
The Sky Institute
for the Future seeks to implement pragmatic and sustainable
strategies in design, energy, town planning, and agricultural
production, and to create and incubate transformational ideas that
will nourish healthy communities and educate current and future
generations
Our Construction and Components
Once
we have designed the system, we will review the design with our
engineering, procurement, and construction partner to maximize the
chances that the project can be delivered according to plan and on
budget. We expect our construction contracts to be at a fixed price
and to include penalties if the construction timetable is missed.
We may, but are not obligated to, engage DCO Energy to construct
our plants or serve as our owners’ engineer.
In our systems, the two most important components
are heat exchangers and deep-water intake pipes. Although there are
multiple providers of each of these components, the supply of the
best components comes from just a few companies globally. We expect
to source our deep-water intake pipes from Pipelife of Norway, the
only company we know of that makes pipes of sufficient
quality, strength, and diameter (2.5
meters) to support our planned OTEC plants. However, we expect that
we could work around a lack of supply from Pipelife by using
multiple smaller pipes that are widely available on the market,
although this would increase our construction
costs.
We
will also need the highest quality, large heat exchangers for our
systems; heat exchangers represent a large percentage of the
projected costs of our OTEC and SWAC/LWAC systems and also account
for a significant portion of the complexity inherent in commercial
OTEC and SWAC/LWAC designs. Our relationship with Alfa Laval
provides us with the size and quality of heat exchangers that we
expect to need, although we believe there are several other
companies that could provide us with adequate supply of these
devices meeting our specifications if we need to source from
them.
Other
major components, such as ammonia turbines, generators, and pumps,
are manufactured by several multinational companies, including
General Electric and Siemens.
Our Operations
For
OTEC electricity-generating facilities, we intend to enter into 20-
to 30-year power purchase agreements, or PPAs, pursuant to which
the project would supply fixed-price, baseload electricity to
satisfy the minimum demand of the purchaser’s customers. This
PPA structure allows customers to plan and budget their energy
costs over the life of the contract. For our SWAC/LWAC systems, we
intend to enter into 20- to 30-year energy service agreements, or
ESAs, to supply minimum quantities of chilled water for use in a
customer’s air conditioning system.
We
anticipate that operations of OTEC and SWAC/LWAC plants will be
subcontracted to third parties that will take responsibility for
ensuring the efficient operation of the plants. These arrangements
may reduce our exposure to operational risk, although they may also
reduce our financial return if actual operating costs are less than
the subcontract payments. We cannot assure that any OTEC and
SWAC/LWAC plants will permit the PPAs and ESAs to yield minimum
target internal rates of return. Our first projects are likely to
have lower returns than subsequent projects. Variances in internal
rates of return may occur due to a range of factors, including
availability and structure of project financing and localized
issues such as taxes, some of which may be outside of our
control.
We expect our OTEC contract pricing will be
charged either on an energy-only price per kWh or on the basis of a
capacity payment priced per kilowatt per month and an energy usage
price per kWh. We cannot assure that this pricing will enable us to
recoup our funding and project costs and allow us to earn a
profit.
Marketing Strategies
Our marketing and sales efforts are managed and
directed by our
chairman and chief executive officer,
Jeremy P. Feakins, who has 35 years’ experience of
senior-level sales in both commercial and governmental markets. Our
marketing campaign has focused on explaining to potential customers
the economic, environmental, and other benefits of OTEC and
SWAC/LWAC through personal contacts, industry interactions, and our
website.
Our
target markets are comprised of large institutional customers that
typically include governments, utilities, large resorts, hospitals,
educational institutions, and municipalities. We market to them
directly through personal meetings and contact by our chief
executive officer and other key members of our team. We also make
extensive use of centers of influence either to heighten awareness
of our products in the minds of key customers’
decision-makers or to secure face-to-face meetings and preliminary
agreements between our customers and our chief executive
officer.
Sales
cycles in our business are extremely long and complex and often
involve multiple meetings with governmental, regulatory, electric
utility, and corporate entities. Therefore, we cannot predict when
or if any of the projects we currently have under development will
progress to a signed contract or operational phase and generate
revenue. We do not expect sales to be seasonal or
cyclical.
Material Regulation
Our
business and products are subject to material regulation. However,
because we contemplate offering our products and services in
different countries, the specific nature of the regulatory
requirements will be wholly dependent on the nation where the
project will be located and the national, state, and local
regulations that apply at that location. In all cases, we expect
the level of regulation will be material and will require
significant permitting and ongoing compliance during the life of
the project.
The
most significant regulations will likely be environmental and will
include mitigating possible adverse effects during both the
construction and operational phases of the project. However, we
believe that the limited plant site disturbance of both SWAC/LWAC
and OTEC projects, together with the significantly lower emissions
that result from these projects as compared to fossil-fuel
electrical generation, will make compliance with all such
regulation manageable in the normal course.
The
second most significant regulations will likely involve
coordination with existing infrastructure. We believe compliance
with this type of regulation is a routine civil engineering
coordination process that exists for all new buildings and
infrastructure projects of all types. Again, we believe that the
design of both SWAC/LWAC and OTEC projects can readily be modified
to avoid interference with existing infrastructure in most
cases.
Facilities
Our
principal executive offices are located at 800 South Queen Street,
Lancaster, Pennsylvania 17603. Our telephone number at that address
is (717) 299-1344.
Intellectual Property
We
use, or intend to employ in the performance of our material
contracts, intellectual property rights in relation to the design
and development of OTEC plants. Our intellectual property rights
can be categorized broadly as proprietary know-how, technical
databases, and trade secrets comprising concept designs, plant
design, and economic models. Additionally, we have applied to
register the trademark TOO DEEP® at the U.S. Patent and
Trademark Office for the provision of desalinated deep ocean water
for consumption. The U.S. Patent and Trademark Office has approved
an extension of our Notice of Allowance until April 9,
2020.
We
may apply for patents for components of our intellectual property
for OTEC and SWAC/LWAC systems, including novel or new
methodologies for cold-water piping, heat exchanges, and
computer-aided design programs. We cannot assure that any patents
we seek will be granted.
Our
intellectual property has been developed by our employees and is
protected under employee agreements confirming that the rights in
the inventions and developments made by the employees are our
property. Confidential information is protected by nondisclosure
agreements we entered into with prospective partners or other third
parties with which we do business.
We
have not received any notification from third parties that our
processes or designs infringe any third-party rights, and we are
not aware of any valid and enforceable third-party intellectual
property rights that infringe our intellectual property rights.
Currently, there is no patent for any company for OTEC
technology.
Employees
We
currently have five employees, consisting of one officer, three
engineers/technicians, and one general and administrative employee,
and three consultants. There are no collective-bargaining
agreements with our employees, and we have not experienced work
interruptions or strikes. We believe our relationship with
employees is good, and we provide health and life insurance for all
employees.
Investing in our common stock involves a high degree of risk.
Investors should carefully consider the risks described below, as
well as the other information in this report, including our
financial statements and the related notes and
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations,” before deciding whether
to invest in our common stock. The occurrence of any of the events
or developments described below could harm our business, financial
condition, operating results, and growth prospects. In such an
event, the market price of our common stock could decline, and
investors may lose all or part of their investment. Additional
risks and uncertainties not presently known to us or that we
currently deem immaterial also may impair our business
operations.
Risks Related to Our Financial Condition
The auditors’ report for the years ended December 31, 2019
and 2018, contains an explanatory paragraph about our ability to
continue as a going concern.
The
report of our auditors on our consolidated financial statements for
the years ended December 31, 2019 and 2018, as well as for prior
years, contains an explanatory paragraph raising substantial doubt
about our ability to continue as a going concern. We had a net loss
of $4,880,191 and $7,880,013, respectively; used cash in operations
of $616,780 and $1,638,582, respectively; had a working capital
deficiency of $21,882,907 and $17,601,515, respectively; and had an
accumulated deficit of $80,463,422 and $75,583,231, respectively,
at December 31, 2019 and 2018. This raises substantial doubt about
our ability to continue as a going concern. Our ability to continue
as a going concern beyond December 31, 2019, is dependent on our
ability to raise additional capital through the sale of debt or
equity securities or stockholder loans and to implement our
business plan during the next 12 months. The financial statements
do not include any adjustments that might be necessary if we are
unable to continue as a going concern. Management believes that
actions presently being taken to obtain additional funding through
implementing our strategic plans, broadly based marketing strategy,
and sales incentives to expand operations will provide the
opportunity for us to continue as a going concern.
We have no current project that will generate revenues in the near
future.
None of
our several projects is to the development stage at which it will
generate revenues in the near future. Our project development
cycles are relatively long, extending over several years as we
identify a potential project site, complete negotiations with third
parties, complete permitting, obtain financing, complete
construction, and place a plant into service. We expect to receive
a development fee of approximately 3% of the project cost from our
projects, payable upon the close of project financing. Operating
revenues from projects are expected to be received when the plant
has been built and placed into operation. We are currently focusing
on developing a U.S. Virgin Island project, but even if we develop
it successfully, it will not generate revenues until several years
in the future. Until we receive revenues from this or another
project, we will be dependent on raising funds from external
sources.
We will require substantial amounts of additional capital from
external sources.
We do
not have any current source of revenues or sufficient cash or other
liquid resources to fund our planned activities until we receive
development fees from new contracts. Accordingly, as in the past,
we will need substantial amounts of capital from external sources
to fund day-to-day operations and project development. We have no
arrangements or commitment for such capital. We plan to continue
our practice of seeking external capital through the sale of debt
or equity, although we cannot assure that such efforts will be
successful and the current coronavirus disease 2019
(“COVID-19”) pandemic may make it more difficult to
raise additional capital. Any new investments will dilute the
interests of the current stockholders. Further, new investors may
require preferential financial returns, security, voting rights, or
other preferences that will be superior to the rights of the
holders of common stock. Alternatively, as project development
advances, we may be required to sell all or a portion of our
interest in one or more projects, which could reduce our retained
financial interest and potential return.
Risks Related to Our Business
Our efforts to develop OTEC and SWAC/LWAC plants are subject to
many financial, technical, managerial, and sales risks that may
make us unsuccessful.
We
incur substantial costs that we may not recover developing a new
project that we may not build, operate, or sell. The identification
of suitable locations, the investigation of the applicable
regulatory and economic framework, the identification of potential
purchasers, the completion of preliminary engineering and planning,
and the funding of related administrative and support costs
ordinarily require several years to complete before we determine to
further develop or abandon a project. Each of these steps is
fraught with risks and uncertainties, such as:
●
limited market due
to low demand, existing competitive energy sources, low power
costs, or the absence of a single or few large potential output
purchasers;
●
a regulatory scheme
suggesting that the development and operation of a plant would be
subject to excessively stringent utility regulations or
environmental requirements, burdensome zoning or permitting
practices and requirements, or similar factors;
●
shortage of
suitable onshore locations, lack of available cold water with
near-shore accessibility, sea wave and current conditions, and
exposure to hurricanes, typhoons, earthquakes, or similar extreme
events;
●
the unavailability
of favorable tax or other incentives or excessively stringent
applicable incentive requirements;
●
the high cost and
potential regulatory difficulties in integrating into new
markets;
●
the possibility
that new markets may be limited or unstable or our exposure to
competition from other sources of existing or potentially new
energy sources;
●
difficulties in
negotiating power purchase agreements (PPAs) with potential
customers, including in some instances, the necessity to assist in
the formation of a power purchasing group; and
●
the need to educate
the market as well as investors regarding the reliability and
economical and environmental benefits of ocean thermal
technologies.
We
cannot assure that we will be able to overcome these risks as we
initiate the development of a project. We may incur substantial
costs in advancing a project through the early stages, only to
conclude eventually that the project is not economically or
technically feasible, in which case we may be unable to recover the
costs that we have then incurred. When we elect to proceed with a
project, we may continue to incur substantial costs and be unable
to complete the development, sell the project, or otherwise recover
our investment. Even when a project is developed, constructed, and
placed into operation, we cannot assure that we will be able to
operate at a profit sufficient to recover our total
investment.
We are dependent on the performance of counterparties to our
agreements.
Our
projects are and will be complex, with a number of agreements among
several parties that purchase plant outputs; provide financing;
complete design, construction, and other services; design and
perform regulatory compliance; and fulfill other requirements. The
failure of any participant in one of our projects due to its own
management, financial, operating, or other deficiencies, all of
which may be outside our control, can materially and adversely
affect our operations and financial results. In circumstances in
which we are not the prime developer of a large-scale project
involving many components in addition to our OTEC, SWAC/LWAC, or
other components, we would have little ability to address problems
resulting from performance failures by others or implement
project-wide remedial measures. The foregoing is illustrated in our
Baha Mar project, which is now on hold, and may never resume,
because of contract performance and financing disputes by
others.
Ongoing world economic, currency-exchange, energy-price, contagious
disease, and political circumstances adversely affect our project
development activities.
Recent
and ongoing world events outside of our control or influence
adversely affect our development activities. Economic uncertainties
have resulted in the unpredictable availability of credit, debt,
and equity financing; volatile interest rates; currency
exchange-rate fluctuations that add risk to international projects;
restrictions on the availability of borrowing; concerns respecting
inflation and deflation; economic turmoil resulting from
unpredictable political events, tensions in international
relations, and the current COVID-19 pandemic; substantial
reductions in hydrocarbon energy prices and the impact of such
declines on the cost of energy generally; shifts in the economic
feasibility of competitive energy sources; and similar factors.
These adverse factors frequently have a particularly intense effect
on emerging markets and developing countries, which we believe
provide the greatest opportunity for our development of our
projects. The possibility that principal energy prices will
continue at current or even lower levels, which could reduce the
projected cost at which power could be generated by
hydrocarbon-fueled power plants, could make our relatively
higher-cost plants less competitive. These emerging and developing
markets are particularly vulnerable to the negative impacts of
these adverse circumstances. The economic feasibility of
alternative energy, including the process we develop and propose to
operate, as compared to hydrocarbon energy is adversely affected as
the prices for hydrocarbon fuels decline. Accordingly, possible
continuing low hydrocarbon prices may retard the potential increase
in the economic feasibility of alternative energy. The decline in
crude oil prices from over $100 per barrel several years ago to
approximately one quarter of that today has adversely affected
alternative energy development. Our ability to develop and operate
alternative energy plants and our ability to generate revenue will
be adversely affected by continuing, relatively soft hydrocarbon
energy prices. Further, alternative energy development may be
adversely affected by uncertainty in hydrocarbon prices or public
expectations that hydrocarbon prices may continue to
decline.
We require substantial amounts of capital for all phases of our
proposed activities.
We
require substantial amounts of capital to fund efforts to identify,
research, preliminarily engineer, permit, and design our projects
and to negotiate PPAs for them. These costs may not be recovered,
because we may not elect to complete the development of the project
or because the development and operation of the project are not
successful. We will rely on external capital to fund all of our
operations, and we cannot assure that such capital will be
available. In recent weeks, the continued spread of COVID-19 has
led to disruption and volatility in the global capital markets,
which increases the cost of capital and adversely impacts access to
capital. Our efforts to access capital markets will be limited,
particularly at the outset, because we have not yet developed and
placed into operation our first plant. Accordingly, we expect that
we will have to provide the potential for a significant economic
return for the initial capital we obtain, which will likely dilute
the interests of our existing stockholders. We expect that each
project that we are able to fully develop, construct, and place
into operation will require several stages and levels of debt and
equity financing. For example, we expect that a 20-MW OTEC plant
may require total capital expenditures of approximately $445
million, consisting of $365 million in project debt financing and
$80 million in equity. We cannot assure that we will be able to
obtain financing, and if obtained, such financing may be on terms
that we will retain only a minority financial interest in the
completed project and its operations. Our inability to obtain
required financing for any activity or project could have a
material adverse effect on our activities and
operations.
We are reliant on our key executives and personnel.
Our
business, development, and prospects are highly dependent upon the
continued services and performance of our directors and other key
personnel, on whom we rely for experience, technical skills, and
commercial relationships. We believe that the loss of services for
any reason of any existing key executives, or failure to attract
and retain necessary personnel, could have a material adverse
impact on our business, development, financial condition, results
of operations, and prospects. Although we have entered into
employment agreements with our key executives, we may not be able
to retain them. We do not maintain key-man life insurance on any of
our executive employees.
Our projects will be subject to substantial regulations and
policies governing energy projects, power generation, desalinated
water sales, and other aspects of our OTEC and SWAC/LWAC plants,
which may adversely affect our ability to develop projects, and any
changes in the applicable regulatory schemes may adversely affect
projects that we are constructing or have constructed and are
operating.
Our
projects likely will be significant commercial or industrial
enterprises in each of their locations and, as such, will be
subject to numerous environmental, health and safety,
antidiscrimination, and similar laws and regulations in each of the
jurisdictions governing our locations. These laws and regulations
will require our projects to obtain and maintain permits and
approvals; complete environmental impact assessments or statements
prior to construction; and review processes and operations to
implement environmental, health and safety, antidiscrimination, and
other programs and procedures to control risks associated with our
operations.
Environmental
health and safety laws, regulations, and permit requirements
applicable to any specific project at the time of construction may
change or become more stringent during the life of the operation.
Any such changes could require that our projects incur substantial
additional costs, alter their operations, or limit or curtail their
operations in order to comply, which would have a material adverse
effect on our operations. We may not be able to pass on any
additional costs that we incur to our power purchasers,
particularly in those cases in which we sell power pursuant to a
long-term, fixed-price agreement.
The financial model for our proposed projects has not been tested
and may not be successful.
We are
proposing a financial model for the development of individual
projects that includes development financing provided by us,
construction financing provided by equity investors in the specific
projects, and project debt financing; the payment of a development
fee to us at the time of construction; and continuing equity
participation by us throughout the plant’s operation. We have
not used this model in the financing or completion of any plant,
and we cannot assure that the financial model and, therefore, the
anticipated financial return to us will be acceptable to those that
might provide the requisite external capital.
We may
need to revise extensively our financing structure for each
project, and we cannot assure that any restructured proposal would
not substantially reduce our financial return or increase our risk.
The financial, investment, and credit community are generally
unfamiliar with OTEC and SWAC/LWAC projects, which will adversely
affect our financing efforts. We have no existing relationships
with potential sources of debt or equity capital, and any financing
sources that we may develop may be inadequate to support the
anticipated capital needs of our business. Our efforts to obtain
financing may be adversely affected by the fact that our projects
will likely be located in developing or emerging markets. Our
inability to obtain financing may force us to abandon projects in
which we have invested substantial costs, which we may be unable to
recover. The process of identifying new sources of debt and equity
financing and agreeing on all relevant business and legal terms
could be lengthy and could require us to limit the rate at which we
can develop projects or reduce our financial return.
We may be exposed to political and legal risks in the developing or
emerging markets in which we propose to locate plants.
Many of
the markets that may be suitable for a potential OTEC or SWAC/LWAC
plants are located in emerging or developing countries that may
have evolving and untested regulatory and legal environments for
large-scale, international, commercial enterprises. Further,
political instability, regime change, or other factors may increase
uncertainty and instability, which in turn may adversely affect our
ability to secure necessary regulatory approvals and obtain
required project financing, which increases related costs and
reduces our financial return. Any changes in applicable laws and
regulations, including any governmental incentives, environmental
requirements or restrictions, safety requirements, and similar
matters, and the risk or likelihood of such a change could
adversely affect the availability and cost of financing. Further,
in some jurisdictions, applicable legal requirements may not have
been fully tested and are still being developed in the face of
modern international commercial transactions and environmental
requirements, which may lead to changes in interpretation or
application that may be adverse to us. Our expectations regarding
the size of the potential OTEC and SWAC/LWAC markets and the number
of possible suitable locations may not be accurate.
Our
business plan and models are based on our identification of
potential suitable locations for OTEC or SWAC/LWAC plants based on
a preliminary evaluation of public information respecting
demographic data, current power-generation costs, and local
seafloor contours and seawater temperatures, which may be
inaccurate. Any material inaccuracy could substantially reduce the
total market available to us for plant development.
We may
be unable to arrange or complete future construction projects on
time, within expected budgets, or without interruption due to
materials availability and disruptions in supply, labor, or other
factors. If any project reaches the point at which we undertake
construction, such construction may be subject to actual prices
higher than the amount budgeted, the limited or delayed
availability of components or materials, shortages or interruptions
of labor or materials, or similar circumstances. In the case we
have insufficient budget flexibility to pay increased construction
costs, corresponding delays could result to construction completion
and the commencement of operations.
Emerging markets
are often associated with growth rates that may not be sustainable
and may be accompanied by periods of high inflation. Rising
inflation or related government monetary and economic policies in
certain project jurisdictions may affect our ability to obtain
external financing and reduce our ability to implement our
expansion strategy. We can give no assurances that a local
government will not implement general or project-specific measures
to tighten external financing standards, or that if any such
measure is implemented, it will not adversely affect our future
operating results and profitability.
We are subject to changing attitudes about environmental
risks.
Our
projects may face opposition from environmental groups that may
oppose our development, construction, or operation of OTEC or
SWAC/LWAC plants. Each project is expected to have different
environmental issues, especially as many of our projects are based
in different settings having a wide range of environmental
standards. We intend to solicit input from environmental
organizations and activists early in our design process for our
projects in an effort to consider appropriately these
organizations’ recommendations in order to mitigate
subsequent conflict or opposition, but we cannot assure that such
outreach will be effective in all cases, and if it is not,
opposition to our projects could increase our cost and adversely
affect the results of our operations.
We may be unable to find land suitable for our
projects.
Each
project site requires land of differing characteristics to permit
the cost-effective construction of OTEC or SWAC/LWAC plants, and
suitable land may not always be available. Even if available, such
land may be difficult to obtain in a timely or cost-effective
manner. For example, we would prefer to place OTEC power systems
and facilities as close to the ocean as possible. We hope to
mitigate this risk by using land owned by local governments, rather
than private individuals or entities, as targeting local
governments with favorable energy policies or mandates should
reduce land rights risks. Our inability to secure appropriate land
at a reasonable cost may render certain of our future projects
economically unfeasible.
We have a limited number of suppliers for certain materials, which
could increase our costs or delay completion of
projects.
In our
systems, the two most important components are heat exchangers and
deep-water intake pipes. Although there are multiple providers of
each of these components, the supply of the best components comes
from just a few companies globally. Should these resources become
unavailable for any reason or too costly, we would be required to
seek alternative suppliers. The products from such suppliers could
be of a lower quality or more costly, in any event requiring us to
expend additional monies or time to complete our projects as
planned. This could result in financial penalties or other costs to
us.
There may be greater cost in building OTEC plants that generate
over 10 MWs of electricity.
In
order to successfully obtain debt financing for OTEC facilities, we
must find engineering, procurement, and construction contractors
willing to enter into fixed-price contracts at a pricing that is
economically viable for us. Based on our preliminary discussions,
we believe that engineering, procurement, and construction
contractors may be willing to consider fixed-price arrangements for
up to 10-MW OTEC facilities, but we have not yet discussed
performance risk guarantees for OTEC plants greater than 10 MWs.
The cost of construction for larger OTEC power systems may vary
considerably, and these variances could include increased costs for
construction, design, and component procurement. As we gain more
experience, we may improve upon efficiencies and accuracy in
pricing. Failure to procure engineering, procurement, and
construction contractors willing to perform fixed-price contracts
on facilities that produce more than 20 MWs may have a material
adverse effect on our operations.
Technological advances may render our technologies, products, and
services obsolete.
We
operate in a fast-moving sector in which innovative forms of power
generation and new energy sources are continuously being
researched. New technologies may be able to provide power, coolant,
desalinated seawater, or other outputs at a lower cost, including
amortization of capital costs, or with less environmental impact.
We will remain subject to these risks for the useful life of our
projects, which could extend for 20 years or more. Any such
technological improvements could render our projects
obsolete.
We may not successfully manage growth.
We
intend to continue to develop the projects in our pipeline of
opportunities and to construct and operate plants as we deem
warranted and as we are able to finance. This is an ambitious
growth strategy. Our growth and future success will depend on the
successful completion of the expansion strategies and the
sufficiency of demand for our energy products. The execution of our
expansion strategies may also place a strain on our managerial,
operational, and financial reserves. Should we fail to effectively
implement such expansion strategies or should there be insufficient
demand for our products and services, our business operations,
financial performance, and prospects would be adversely
affected.
There will likely be a single or limited number of power purchasers
from each plant, so we will be dependent on their economic
viability and stability and continued operations.
We
expect that any plant that we operate will provide power, cooling,
desalinated water, or other products to a few or a limited number
of key power purchasers that will use the power for specific
commercial enterprises, such as resorts, manufacturing or
processing plants, or similar large-scale operations. Accordingly,
our ability to sell power and other outputs will be dependent on
the economic viability of these purchasers. If one or more key
purchasers were to fail, we would be required to obtain alternative
purchasers for our power and other outputs, and there may be no or
a limited number of alternative purchasers in the merging and
developing markets where we anticipate our plants may be located.
Accordingly, a failure of an output purchaser may result in the
failure of our power plant project. We do not anticipate that we
will be able to obtain insurance on acceptable terms to protect us
against such a loss. Further, our project output purchasers may not
comply with contractual payment obligations or may otherwise fail
to perform their contracts, and they may have greater economic
bargaining power and negotiating leverage as we seek to enforce our
contractual rights. To the extent that any of our project power
purchasers are, or are controlled by, governmental entities, our
projects may also be subject to legislative, administrative, or
other political action or policies that impair their contractual
performance. Any failure of any key power purchasers to meet their
contractual obligations for any reason could have a material
adverse effect on our business and operations.
Operational problems, natural events or catastrophes, casualty
loss, or other events may impair the commercial operation of our
projects.
Our
ability to meet our delivery obligations under power-generation
contracts, as well as our ability to meet economic projections,
will depend on our ability to maintain the efficient working order
of our plants. Severe weather, natural disasters, accidents,
failure of significant equipment components, inability to obtain
replacement parts, failure of power transmission facilities, or
other catastrophes or occurrences could materially interrupt our
activities and consequently reduce our economic return. Since all
of our plants will be located on the shore within close proximity
to deep-ocean or lake water, our plants will be subject to
extraordinary natural occurrences, such as wave surges from
hurricanes or typhoons, tsunamis, earthquakes, and other events,
over which we will have absolutely no control. We cannot assure
that we can obtain sufficient insurance to protect us from all
risks resulting from such catastrophes. Further, we cannot assure
that any design features or operating policies that we may use will
mitigate the risks to which our plants may be exposed. Any
threatened or actual events could expose us to plant shutdowns,
substantial repairs, interruptions of operations, damages to our
power purchasers, and similar events that could require us to incur
substantial costs and significantly impair our revenues and results
of operations.
We may be adversely affected by climate change.
Climate
change may result in changes in ocean currents and water
temperatures that could have a material adverse effect on our
results of operations. These changes may require additional capital
costs or impair the efficiency of our operations. Because of the
size and cost of major components of our power plants, we typically
will not inventory spare components, so that any substantial damage
may require that we await the custom manufacture and delivery of
such items, which may involve substantial delays. Significant
changes may render any plant inefficient and
uneconomical.
Insurance to cover anticipated risks may become more
expensive.
There
are no known commercial OTEC and SWAC/LWAC plants in operation, so
the nature and cost of insurance is difficult to predict. Insurance
costs may substantially exceed the costs forecast during the
planning process or budgeted during actual operations. We cannot
assure that adequate insurance coverage will be available to
protect us against all risks or that any related costs will be
economical. Accordingly, if we are unable or cannot afford to
purchase insurance against specific risks, our projects may be
fully exposed to those risks, which also could have a material
adverse effect on the viability of any affected plant.
Risks Related to Our International Operations
Certain risks of loss arise from our need to conduct transactions
in foreign currencies.
Our
business activities outside the United States and its territories
may be conducted in foreign currencies. In the future, our capital
costs and financial results may be affected by fluctuations in
exchange rates between the applicable currency and the dollar.
Other currencies used by us may not be convertible at satisfactory
rates. In addition, the official conversion rates between a
particular foreign currency and the U.S. dollar may not accurately
reflect the relative value of goods and services available or
required in other countries. Further, inflation may lead to the
devaluation of such other currencies.
Foreign governmental entities may have the authority to alter the
terms of our rights or agreements if we do not comply with the
terms and obligations indicated in such agreements.
Pursuant to the
laws in some jurisdictions in which we may develop or operate
plants, foreign governmental entities may have the authority to
alter the terms of our contractual or financial rights or override
the terms of privately negotiated agreements. In extreme
circumstances, some foreign governments have taken the step of
confiscating private property on the assertion that such action is
necessary in the public interest of the country. If this were to
occur, we may not be compensated fairly or at all. We cannot assure
that we have complied, and will comply, with all the terms and
obligations imposed on us under all foreign laws to which one or
more of our operations and assets may be subject.
Our operations will require our compliance with the Foreign Corrupt
Practices Act.
We must
conduct our activities in or related to foreign companies in
compliance with the U.S. Foreign Corrupt Practices Act, or FCPA,
and similar anti-bribery laws that generally prohibit companies and
their intermediaries from making improper payments to foreign
government officials for the purpose of obtaining or retaining
business. Enforcement officials interpret the FCPA’s
prohibition on improper payments to government officials to apply
to officials of state-owned enterprises, including state-owned
enterprises with which we may develop or operate projects or to
which we may sell plant outputs. While our employees and agents are
required to acknowledge and comply with these laws, we cannot
assure that our internal policies and procedures will always
protect us from violations of these laws, despite our commitment to
legal compliance and corporate ethics. The occurrence or allegation
of these activities may adversely affect our business, performance,
prospects, value, financial condition, reputation, and results of
operations.
Our competitors may not be subject to laws similar to the FCPA,
which may give them an advantage in negotiating with underdeveloped
countries and the government agencies.
Our
competitors outside the United States may not be subject to
anti-bribery or corruption laws as encompassing or stringent as the
U.S. laws to which we are subject, which may place us at a
competitive disadvantage.
We may encounter difficulties repatriating income from foreign
jurisdictions.
As we
develop and place plants into operation, we intend to enter into
revenue-generating agreements in which we are paid only in U.S.
dollars directly to our U.S. banks or through countries in which
repatriation of the funds to our U.S. accounts is unrestricted.
However, situations could arise in which we agree to accept payment
in foreign jurisdictions and for which restrictions make it
difficult or costly to transfer these funds to our U.S. accounts.
In this event, we could incur costs and expenses from our U.S.
assets for which we cannot recover income directly. This could
require us to obtain additional working capital from other sources,
which may not be readily available, resulting in increased costs
and decreased profits, if any.
Risks Related to Our Common Stock
Our common stock is thinly traded, and there is no guarantee of the
prices at which the shares will trade.
Our
common stock is quoted on the OTCQB Marketplace operated by the OTC
Markets Group, Inc., under the ticker symbol “CPWR.”
Not being listed on an established securities exchange has an
adverse effect on the liquidity of our common stock, not only in
terms of the number of shares that can be bought and sold at a
given price, but also through delays in the timing of transactions
and reduction in security analysts’ and the media’s
coverage of our company. This may result in lower prices for our
common stock than might otherwise be obtained and could also result
in a larger spread between the bid and asked prices for our common
stock. Historically, our common stock has been thinly traded, and
there is no guarantee of the prices at which the shares will trade
or of the ability of stockholders to sell their shares without
having an adverse effect on market prices.
We have never paid dividends on our common stock and we do not
anticipate paying any dividends in the foreseeable
future.
We have
not paid dividends on our common stock to date, and we may not be
in a position to pay dividends in the foreseeable future. Our
ability to pay dividends depends on our ability to successfully
develop our OTEC business and generate revenue from future
operations. Further, our initial earnings, if any, will likely be
retained to finance our growth. Any future dividends will depend
upon our earnings, our then-existing financial requirements, and
other factors and will be at the discretion of our board of
directors.
Because our common stock is a “penny stock,” it may be
difficult to sell shares of our common stock at times and prices
that are acceptable.
Our
common stock is a “penny stock.” Broker-dealers that
sell penny stocks must provide purchasers of these stocks with a
standardized risk disclosure document prepared by the SEC. This
document provides information about penny stocks and the nature and
level of risks involved in investing in the penny stock market. A
broker must also give a purchaser, orally or in writing, bid and
offer quotations and information regarding broker and salesperson
compensation, make a written determination that the penny stock is
a suitable investment for the purchaser, and obtain the
purchaser’s written agreement to the purchase. The penny
stock rules may make it difficult for investors to sell their
shares of our common stock. Because of these rules, many brokers
choose not to participate in penny stock transactions and there is
less trading in penny stocks. Accordingly, investors may not always
be able to resell shares of our common stock publicly at times and
prices that they feel are appropriate.
In
addition to the “penny stock” rules described above,
the Financial Industry Regulatory Authority (known as
“FINRA”) has adopted rules that require that in
recommending an investment to a customer, a broker-dealer must have
reasonable grounds for believing that the investment is suitable
for 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 an investor’s ability to buy and sell
our stock and have an adverse effect on the market for our
shares.
Investors may lose confidence in the accuracy and completeness of
our financial reports and the market price of our common stock may
be negatively affected.
As a
public reporting company, we are subject to the Sarbanes-Oxley Act
of 2002 as well as to the information and reporting requirements of
the Securities Exchange Act of 1934, as amended (the
“Exchange Act”), and other federal securities laws. As
a result, we incur significant legal, accounting, and other
expenses, including costs associated with our public company
reporting requirements and corporate governance requirements. As an
example of public reporting company requirements, we evaluate the
effectiveness of disclosure controls and procedures and of our
internal control over financing reporting in order to allow
management to report on such controls.
Our
management concluded that our internal control over financial
reporting was not effective as of December 31, 2019, due to a
failure to maintain an effective control environment, failure of
segregation of duties, failure of entity-level controls, and our
sole executive’s access to cash.
If
significant deficiencies or other material weaknesses are
identified in our internal control over financial reporting that we
cannot remediate in a timely manner, investors and others may lose
confidence in the reliability of our financial statements. This
would likely have an adverse effect on the trading price of our
common stock and our ability to secure any necessary additional
equity or debt financing.
ITEM 1B. UNRESOLVED STAFF
COMMENTS
None.
Our
principal corporate offices located at 800 South Queen Street,
Lancaster, PA contain approximately 28,000 square feet and are
leased from Queen Street Development Partners 1, LP at $10,000 per
month. Our lease is a month-to-month basis. Queen Street
Development Partners 1, LP is owned by our chief executive officer
and director. We believe the terms of this lease are similar to
those that we could negotiate in an arm’s-length transaction
with an unrelated third party. The facilities and equipment
described above are generally in good condition, well maintained,
and suitable and adequate for our current and projected operating
needs.
ITEM 3. LEGAL PROCEEDINGS
From
time to time, we are involved in legal proceedings and regulatory
proceedings arising from operations. We establish reserves for
specific liabilities in connection with legal actions that
management deems to be probable and estimable.
On May
4, 2018, we reached a settlement of the claims at issue in
Ocean Thermal Energy Corp.
v. Robert Coe, et al., Case No. 2:17-cv-02343SHL-cgc, before
the United States District Court for the Western District of
Tennessee. Between May 30 and July 19, 2018, we received three
payments totaling $100,000 from the defendants. On August 8, 2018,
an $8 million judgment was entered against the defendants and in
our favor. On May 28, 2019, we further settled the claims at issue
with two of the defendants, Brett M Regal and his company, Trade
Base Sales, Inc., for $17,500,000. The combined judgment and
settlement amounts owed to us total $25,500,000. On July 1, 2019,
the United States District Judge for the Central District of
California (case number: 2:19-cv-05299-VAP-JPR), approved our
stipulated application for an order permitting us to levy on
property, including, but not limited to, certain gemstone and
mineral specimens, known as the “Ophir Collection,”
owned by judgment debtors Brett M. Regal and Trade Base Sales, Inc.
(“Regal Debtors”) and appointing a receiver to carry
out the levy on Regal Debtors’ property, such that it may be
sold (subject to further order of the court approving and
confirming such sales), to satisfy the $25,500,000 settlement and
judgment amounts in our favor. On August 15, 2019, the
court-appointed receiver notified the court that he had taken
custody, possession, and control of the “Ophir
Collection” and 350,000 pounds of unrefined gold and other
precious metal bearing ore. By order of the court, the receiver has
the authority to assign, sell, and transfer the debtors’
property. The proceeds of any sales will be used to satisfy the
judgment and settlement agreement, less the amount needed to
satisfy an existing lien (currently estimated at approximately $10
million plus attorneys’ fees) and receivership’s
reasonable costs and fees. This process is ongoing. Information
will be updated as it progresses.
On May
21, 2019, Theodore T. Herman filed a complaint against us in
Theodore T. Herman v.
Ocean Thermal Energy Corporation, Case No. CI-19-04780, in
the Court of Common Pleas of Lancaster County, Pennsylvania,
asserting that he is entitled to payment on the promissory note
described in Note 4: Convertible Notes and Notes Payable. On July
1, 2019, we filed preliminary objections to the complaint, and
subsequently filed an answer and new matter on August 20, 2019, to
which the plaintiff filed a reply on September 9, 2019.
We will continue to defend our position that no further payment of
principal or interest on this note is owed.
On
August 22, 2018, Fugro USA Maine, Inc. (“Fugro”), filed
suit against us in Fugro
USA Marine, Inc. v. Ocean Thermal Energy Corp., Cause No.
2018-56396, in the District Court for Harris County, TX, 165th
Judicial District, seeking approximately $500,000 allegedly owed
for engineering services provided. We have filed an answer
contesting the amounts owed, which we contend are substantially
less than claimed by Fugro.
ITEM 4. MINE SAFETY DISCLOSURES
Not
applicable.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2019 AND DECEMBER 31,
2018
NOTE 1 – NATURE OF BUSINESS AND BASIS OF
PRESENTATION
Ocean
Thermal Energy Corporation is currently in the businesses
of:
● OTEC
and SWAC/LWAC—designing ocean thermal energy
conversion (“OTEC”) power plants and seawater air
conditioning and lake water air conditioning
(“SWAC/LWAC”) plants for large commercial properties,
utilities, and municipalities. These technologies provide practical
solutions to mankind’s three oldest and most fundamental
needs: clean drinking water, plentiful food, and sustainable,
affordable energy without the use of fossil fuels. OTEC is a clean
technology that continuously extracts energy from the temperature
difference between warm surface ocean water and cold deep seawater.
In addition to producing electricity, some of the seawater running
through an OTEC plant can be efficiently desalinated using the
power generated by the OTEC technology, producing thousands of
cubic meters of fresh water every day for use in agriculture and
human consumption in the communities served by its plants. This
cold, deep, nutrient-rich water can also be used to cool buildings
(SWAC/LWAC) and for fish farming/aquaculture. In short, it is a
technology with many benefits, and its versatility makes OTEC
unique.
● EcoVillages—developing
and commercializing our EcoVillages, as well as working to develop
or acquire new complementary assets. EcoVillages are communities
whose goal is to become more socially, economically, and
ecologically sustainable. EcoVillages are communities whose
inhabitants seek to live according to ecological principles,
causing as little impact on the environment as possible. We expect
that our EcoVillage communities will range from a population of 50
to 150 individuals, although some may be smaller. We may also form
larger EcoVillages, of up to 2,000 individuals, as networks of
smaller sub communities. We expect that our EcoVillages will grow
by the addition of individuals, families, or other small groups.
The development of EcoVillages should add significant value to our
existing line of business.
The
consolidated financial statements include the accounts of the
company and our wholly owned subsidiaries. Intercompany accounts
and transactions have been eliminated in consolidation. In the
opinion of management, our financial statements reflect all
adjustments that are of a normal recurring nature necessary for
presentation of financial statements in accordance with U.S.
generally accepted accounting principles (GAAP).
Principal Subsidiary Undertakings
Our
consolidated financial statements for the years ended December 31,
2019 and 2018, include the following subsidiaries:
|
Name
|
|
Place of Incorporation / Establishment
|
|
Principal Activities
|
|
Date Formed
|
|
Ocean
Thermal Energy Bahamas Ltd.
|
|
Bahamas
|
|
Intermediate
holding company of OTE BM Ltd. and OTE Bahamas O&M
Ltd.
|
|
07/04/2011
|
|
|
|
|
|
|
|
|
|
OTE BM
Ltd.
|
|
Bahamas
|
|
OTEC/SDC
development in the Bahamas
|
|
09/07/2011
|
|
|
|
|
|
|
|
|
|
OCEES
International, Inc.
|
|
Hawaii,
USA
|
|
Research and
development for the Pacific Rim
|
|
01/21/1998
|
We have
an effective interest of 100% in each of our
subsidiaries.
Use of Estimates
In
preparing financial statements in conformity with GAAP, management
is required to make estimates and assumptions that affect the
reported amounts of assets and liabilities and the disclosure of
contingent assets and liabilities at the date of the financial
statements and revenues and expenses during the reported period.
Actual results could differ from those estimates. Significant
estimates include the assumptions used in valuing equity
investments and issuances, valuation of deferred tax assets, and
depreciable lives of property and equipment.
Cash and Cash Equivalents
We
consider all highly liquid temporary cash investments with an
original maturity of three months or less to be cash equivalents.
At December 31, 2019 and 2018, we had no cash
equivalents.
Income Taxes
We use
the liability method of accounting for income taxes. Under the
liability method, deferred tax assets and liabilities are
determined based on temporary differences between financial
reporting and tax bases of assets and liabilities and on the amount
of operating loss carry-forwards and are measured using the enacted
tax rates and laws that will be in effect when the temporary
differences and carry-forwards are expected to reverse. An
allowance against deferred tax assets is recorded when it is more
likely than not that such tax benefits will not be
realized.
Our
ability to use our net operating loss carryforwards may be
substantially limited due to ownership change limitations that may
have occurred or that could occur in the future, as required by
Section 382 of the Internal Revenue Code of 1986, as amended (the
“Code”), as well as similar state provisions. These
ownership changes may limit the amount of net operating loss that
can be utilized annually to offset future taxable income and tax,
respectively. In general, an “ownership change” as
defined by Section 382 of the Code results from a transaction or
series of transactions over a three-year period resulting in an
ownership change of more than 50.0% of the outstanding stock of a
company by certain stockholders or public groups.
We have
not completed a study to assess whether an ownership change has
occurred or whether there have been multiple ownership changes
since we became a “loss corporation” under the
definition of Section 382. If we have experienced an ownership
change, utilization of the net operating loss carryforwards would
be subject to an annual limitation under Section 382 of the Code,
which is determined by first multiplying the value of our stock at
the time of the ownership change by the applicable long-term,
tax-exempt rate, and then could be subject to additional
adjustments, as required. Any limitation may result in expiration
of a portion of the net operating loss carryforwards before
utilization. Further, until a study is completed and any limitation
known, no positions related to limitations are being considered as
an uncertain tax position or disclosed as an unrecognized tax
benefit. Any carryforwards that expire prior to utilization as a
result of such limitations will be removed from deferred tax assets
with a corresponding reduction of the valuation allowance. Due to
the existence of the valuation allowance, it is not expected that
any possible limitation will have an impact on our results of
operations or financial position.
Business Segments
We
conduct operations in various foreign jurisdictions where we are
developing projects to use our technology. Our segments were based
on the location of these projects. The U.S. territories segment
consists of projects in the U.S. Virgin Islands and Guam. Direct
revenues and costs, depreciation, depletion, and amortization
costs, general and administrative costs, and other income directly
associated with their respective segments are detailed within the
following discussion. Identifiable net property and equipment are
reported by business segment for management reporting and
reportable business segment disclosure purposes. Current assets,
other assets, current liabilities, and long-term debt are not
allocated to business segments for management reporting or business
segment disclosure purposes.
Reportable business
segment information is as follows:
|
December 31,
2019
|
|
|
|
|
|
|
Revenue
|
$-
|
$-
|
$-
|
|
Assets
|
$43,243
|
$-
|
$43,243
|
|
Net
loss
|
$(4,880,191)
|
$-
|
$(4,880,191)
|
|
Property
and equipment
|
$-
|
$-
|
$-
|
|
Depreciation
|
$672
|
$-
|
$672
|
|
December 31, 2018
|
|
|
|
|
|
|
Revenue
|
$-
|
$-
|
$-
|
|
Assets
|
$9,070
|
$-
|
$9,070
|
|
Net
Loss
|
$(6,987,374)
|
$(892,639)
|
$(7,880,013)
|
|
Property
and equipment
|
$672
|
$-
|
$672
|
|
Depreciation
|
$680
|
$-
|
$680
|
|
Impairment
of assets under construction
|
$-
|
$892,639
|
$892,639
|
During
the year ended December 31, 2018, $892,639 of assets under
construction in Guam and U.S. Virgin Islands were determined to be
impaired due to the uncertainty of the projects and were written
off; consequently, we had no assets under construction as of
December 31, 2019 and 2018.
Property and Equipment
Furniture,
equipment, and software are recorded at cost and include major
expenditures that increase productivity or substantially increase
useful lives.
Maintenance,
repairs, and minor replacements are charged to expense when
incurred. When furniture, vehicles, or equipment is sold or
otherwise disposed of, the asset and related accumulated
depreciation are removed from this account, and any gain or loss is
included in the statement of operations.
Assets
under construction represent costs incurred by us for our renewable
energy systems currently in process. Generally, all costs incurred
during the development stage of our projects are capitalized and
tracked on an individual project basis and are included in
construction in progress until the project has been placed into
service. If a project is abandoned, the associated costs that have
been capitalized are charged to expense in the year of abandonment.
Expenditures for repairs and maintenance are charged to expense as
incurred. Interest costs incurred during the construction period of
defined major projects from debt that is specifically incurred for
those projects are capitalized.
Direct
labor costs incurred for specific major projects expected to have
long-term benefits are capitalized. Major projects are generally
defined as projects expected to exceed $500,000. Direct labor costs
subject to capitalization include employee salaries, as well as
related payroll taxes and benefits. With respect to the allocation
of salaries to projects, salaries are allocated based on the
percentage of hours that our key managers, engineers, and
scientists work on each project. These individuals track their time
worked at each project. Direct labor includes all of the time
incurred by employees directly involved with construction and
development activities. Time spent in general and indirect
management and in evaluating the feasibility of potential projects
is expensed when incurred.
We
capitalize costs incurred once the project has met the project
feasibility stage. Costs include environmental engineering,
permits, government approval, and site engineering costs. We
capitalize direct interest costs associated with the projects. As
of December 31, 2019 and 2018, we have no interest costs
capitalized for any of these projects.
The
cost of furniture, vehicles, equipment, and software is depreciated
over the estimated useful lives of the related assets.
Depreciation is
computed using the straight-line method for financial reporting
purposes. The estimated useful lives and accumulated depreciation
for computer equipment and software are as follows:
|
|
|
|
Computer
Equipment
|
3
|
|
Software
|
5
|
Fair Value
Financial
Accounting Standards Board (“FASB”) Accounting Standard
Codification (“ASC”) Topic 820, Fair Value Measurements and
Disclosures, defines fair value, establishes a framework for
measuring fair value under GAAP, and enhances disclosures about
fair value measurements. ASC 820 describes a fair value hierarchy
based on three levels of inputs, of which the first two are
considered observable and the last unobservable, that may be used
to measure fair value, which are the following:
●
Valued at quoted
prices adjusted for legal or contractual restrictions specific to
these investments.
●
Own assumptions
about the assumptions market participants would use in pricing the
assets or liability.
Management believes
the carrying amounts of the short-term financial instruments,
including cash and cash equivalents, prepaid expenses, accounts
payable, accrued liabilities, notes payable, deferred compensation,
and other liabilities reflected in the accompanying balance sheets
approximate fair value at December 31, 2019, and December 31, 2018,
due to the relatively short-term nature of these
instruments.
We
accounted for derivative liability at fair value on a recurring
basis under level 3 at December 31, 2019 and 2018 (see Note
5).
Concentrations
Cash,
cash equivalents, and restricted cash are deposited with major
financial institutions, and at times, such balances with any one
financial institution may be in excess of FDIC-insured limits. As
of December 31, 2019, and 2018, $0 and $0, respectively, were
deposited in excess of FDIC-insured limits. Management believes the
risk in these situations to be minimal.
Loss per Share
The
basic loss per share is calculated by dividing our net loss
available to common shareholders by the weighted average number of
common shares during the period. The diluted loss per share is
calculated by dividing our net loss by the diluted weighted average
number of shares outstanding during the period. The diluted
weighted average number of shares outstanding is the basic weighted
number of shares adjusted for any potentially dilutive debt or
equity. We have 350,073 and 350,073 shares issuable upon the
exercise of warrants for the years ended December 31, 2019 and
2018, respectively, and 140,502,788 and 47,046,431 shares issuable
upon the conversion of convertible notes for the years ended
December 31, 2019 and 2018, respectively, that were not included in
the computation of dilutive loss per share because their inclusion
is antidilutive.
Revenue Recognition
In May
2014, the FASB issued Accounting Standard Update
(“ASU”) 2014-09, Revenue from Contracts with Customers (Topic
606). This ASU is a comprehensive new revenue recognition
model that requires a company to recognize revenue to depict the
transfer of goods or services to a customer at an amount that
reflects the consideration it expects to receive in exchange for
those goods or services. We adopted the ASU on January 1, 2018. The
adoption of the ASU did not have an impact on our consolidated
financial statements during the years ended December 31, 2019 and
2018.
Recent Accounting Pronouncements
In
February 2016, the FASB issued ASU 2016-02, Leases, which will amend current lease
accounting to require lessees to recognize: (i) a lease liability,
which is a lessee’s obligation to make lease payments arising
from a lease, measured on a discounted basis; and (ii) a
right-of-use asset, which is an asset that represents the
lessee’s right to use, or control the use of, a specified
asset for the lease term. ASU 2016-02 does not significantly change
lease accounting requirements applicable to lessors; however,
certain changes were made to align, where necessary, lessor
accounting with the lessee accounting model. This standard will be
effective for fiscal years beginning after December 15, 2018,
including interim periods within those fiscal years. We adopted the
provisions of this ASU on January 1, 2019. We have a month-to-month
lease for the office. The adoption had no impact on our
consolidated results of operations, cash flow, or financial
conditions.
In June
2018, the FASB issued ASU 2018-07, Compensation – Stock Compensation (Topic
718): Improvements to Nonemployee Share-Based Payment
Accounting. This ASU relates to the accounting for
non-employee share-based payments. The amendment in this update
expands the scope of Topic 718 to include all share-based payment
transactions in which a grantor acquired goods or services to be
used or consumed in a grantor’s own operations by issuing
share-based payment awards. The ASU excludes share-based payment
awards that relate to: (1) financing to the issuer; or (2) awards
granted in conjunction with selling goods or services to customers
as part of a contract accounted for under Topic 606, Revenue from Contracts from Customers.
The share-based payments are to be measured at grant-date fair
value of the equity instruments that the entity is obligated to
issue when the goods or service has been delivered or rendered and
all other conditions necessary to earn the right to benefit from
the equity instruments have been satisfied. This standard will be
effective for public business entities for fiscal years beginning
after December 15, 2018, including interim periods within that
fiscal year. We adopted the provisions of this ASU on January 1,
2019. The adoption had no impact on our condensed consolidated
results of operations, cash flows, or financial
condition.
We have
reviewed all recently issued, but not yet adopted, accounting
standards in order to determine their effects, if any, on our
consolidated results of operations, financial position, and cash
flows. Based on that review, we believe that none of these
pronouncements will have a significant effect on current or future
earnings or operations.
NOTE 2 – GOING CONCERN
The
accompanying audited condensed consolidated financial statements
have been prepared on the assumption that we will continue as a
going concern. As reflected in the accompanying condensed
consolidated financial statements, we had a net loss of $4,880,191
and used $616,780 of cash in operating activities for the year
ended December 31, 2019. We had a working capital deficiency of
$21,882,907 and a stockholders’ deficiency of $22,066,657 as
of December 31, 2019. These factors raise substantial doubt about
our ability to continue as a going concern. Our ability to continue
as a going concern is dependent on our ability to increase sales
and obtain external funding for our projects under development. The
financial statements do not include any adjustments that may result
from the outcome of this uncertainty. In
recent weeks, the continued spread of COVID-19 has led to
disruption and volatility in the global capital markets, which
increases the cost of capital and adversely impacts access to
capital. The disruption may have an adverse impact on the
Company’s ability to raise capital through debt and/or equity
markets to fund working capital requirements or to continue as a
going concern.
NOTE 3 – PROPERTY AND EQUIPMENT
Property and
equipment as of December 31, 2019 and 2018, consist of the
following:
|
Property and Equipment as of December 31, 2019
|
|
|
|
|
|
Useful Life
|
|
|
|
|
|
Life
|
|
Computer
& Office Equipment
|
$13,751
|
$13,751
|
$-
|
3
Years
|
|
Software
(Video System)
|
19,061
|
19,061
|
-
|
5
Years
|
|
|
$32,812
|
$32,812
|
$-
|
|
|
Property and Equipment as of December 31, 2018
|
|
|
|
|
|
Useful Life
|
|
|
|
|
|
Life
|
|
Computer
& Office Equipment
|
$13,751
|
$13,079
|
$672
|
3
Years
|
|
Software
(Video System)
|
19,061
|
19,061
|
-
|
5
Years
|
|
|
$32,812
|
$32,140
|
$672
|
|
Depreciation
expense for the years ended December 31, 2019 and 2018, was $672
and $680, respectively. There were no
assets under construction as of December 31, 2019. During the year
ended December 31, 2018, $892,639 of Guam and U.S. Virgin Islands
assets under construction were considered to be impaired due to the
uncertainty of the projects and written-off.
NOTE 4 – CONVERTIBLE NOTES AND NOTES PAYABLE
On
December 12, 2006, we borrowed funds from the Southeast Idaho
Council of Governments (SICOG), the EDA-#180 loan. The interest
rate is 6.25%, and the maturity date was January 5, 2013. During
the year ended December 31, 2019, we made a repayment of $4,825.
The loan principal was $4,555 with accrued interest of $0 as of
December 31, 2019. This note is in default.
On
December 23, 2009, we borrowed funds from SICOG, the EDA-#273 loan.
The interest rate is 7%, and the maturity date was December 23,
2014. The loan principal was $94,480 with accrued interest of
$21,918 as of December 31, 2019. This note is in
default.
On
December 23, 2009, we borrowed funds from SICOG, the MICRO I-#274
loan and MICRO II-#275 loan. The interest rate is 7%, and the
maturity date was December 23, 2014. The loan principal was $47,239
with accrued interest of $9,594 as of December 31, 2019. These
notes are in default.
On
December 1, 2007, we borrowed funds from the Eastern Idaho
Development Corporation and the Economic Development Corporation.
The interest rate is 7%, and the maturity date was September 1,
2015. The loan principal was $85,821 with accrued interest of
$45,505 as of December 31, 2019. This note is in
default.
On
September 25, 2009, we borrowed funds from the Pocatello
Development Authority. The interest rate is 5%, and the maturity
date was October 25, 2011. The loan principal was $50,000 with
accrued interest of $23,275 as of December 31, 2019. This note is
in default.
On
March 12, 2015, we combined convertible notes issued in 2010, 2011,
and 2012, payable to our officers and directors in the aggregate
principal amount of $320,246, plus accrued but unpaid interest of
$74,134, into a single, $394,380 consolidated convertible note (the
“Consolidated Note”). The Consolidated Note was
assigned to JPF Venture Group, Inc., an investment entity that is
majority-owned by Jeremy Feakins, our director, chief executive
officer, and chief financial officer. The Consolidated Note was
convertible to common stock at $0.025 per share, the approximate
market price of our common stock as of the date of the issuance. On
February 24, 2017, the Consolidated Note was amended to eliminate
the conversion feature. The Consolidated Note bears interest at 6%
per annum and is due and payable within 90 days after demand. As of
December 31, 2019, the outstanding loan balance was $394,380 and
the accrued but unpaid interest was $119,197 on the Consolidated
Note.
During
2016 and 2015, we borrowed $75,000 from JPF Venture Group, Inc.
pursuant to promissory notes. The terms of the notes are as
follows: (i) interest is payable at 6% per annum;
(ii) the notes are payable 90 days after demand; and
(iii) payee is authorized to convert part or all of the note
balance and accrued interest, if any, into shares of our common
stock at the rate of one share each for $0.03 of principal amount
of the note. This conversion share price was adjusted to $0.01384
for the reverse stock splits. As of December 31, 2018, we have
recorded a debt discount of $75,000 for the fair value derivative
liability and fully amortized the debt discount. As of December 31,
2019, the outstanding balance was $75,000, plus accrued interest of
$16,736.
During
2016, we borrowed $112,500 from JPF Venture Group, Inc. pursuant to
promissory notes. The terms of the notes are as follows:
(i) interest is payable at 6% per annum; (ii) the notes
are payable 90 days after demand; and (iii) payee is
authorized to convert part or all of the note balance and accrued
interest, if any, into shares of our common stock at the rate of
one share for each $0.03 of principal amount of the note. On
February 24, 2017, the notes were amended to eliminate the
conversion features. As of December 31, 2019, the outstanding
balance was $112,500, plus accrued interest of
$25,040.
On
October 20, 2016, we borrowed $12,500 from our independent director
pursuant to a promissory note. The terms of the note are as
follows: (i) interest is payable at 6% per annum;
(ii) the note is payable 90 days after demand; and
(iii) the payee is authorized to convert part or all of the
note balance and accrued interest, if any, into shares of our
common stock at the rate of one share for each $0.03 of principal
amount of the note. This conversion share price was adjusted to
$0.01384 for the reverse stock splits. As of December 31, 2018, we
have recorded a debt discount of $12,500 for the fair value of
derivative liability and fully amortized the debt discount. As of
December 31, 2019, the outstanding balance was $12,500, plus
accrued interest of $2,515.
During
2012, we issued a note payable for $1,000,000. The note had an
interest rate of 10% per annum, was secured by a first lien in all
of our assets, and was due on February 3, 2015. On March 6, 2018,
the note was amended to extend the due date to December 31, 2018.
On March 29, 2019, the maturity date of the note was extended to
December 31, 2019. As of December 31, 2019, the outstanding balance
was $1,000,000, plus accrued interest of $738,337. This note is in
default.
During
2013, we issued Series B units. Each unit is comprised of a note
agreement, a $50,000 promissory note that matures on September 30,
2023, and bears interest at 10% per annum payable annually in
arrears, and a security agreement. During 2013, we issued $525,000
of 10% promissory notes. As of December 31, 2019, the loan balance
was $158,334 and the accrued interest was $101,000.
During
2013, we issued a note payable for $290,000 in connection with the
reverse merger transaction with Broadband Network Affiliates, Inc.
We have determined that no further payment of principal or interest
on this note should be made because the note holder failed to
perform his underlying obligations giving rise to this note. As
described in the litigation section of this filing, the note holder
filed suit on May 21, 2019, and we remain confident that the court
will decide in our favor by either voiding the note or awarding
damages sufficient to offset the note value. As of December 31,
2019, the balance outstanding was $130,000, and the accrued
interest as of that date was $61,402. This note is in
default.
On
January 18, 2018, Jeremy P. Feakins & Associates, LLC, an
investment entity owned by our chief executive, chief financial
officer, and a director, agreed to extend the due date for
repayment of a $2,265,000 note issued in 2014 to the earlier of
December 31, 2018, or the date of the financial closings of our
Baha Mar project (or any other project of $25 million or more),
whichever occurs first. As of December 31, 2019, the note balance
was $1,102,500 and the accrued interest was $629,047. This note is
in default.
We have
$300,000 in principal amount of outstanding notes due to unrelated
parties, issued in 2014, in default since 2015, accruing interest
at a default rate of 22%. We intend to repay the notes and accrued
interest upon the Baha Mar SWAC/LWAC project’s financial
closing. Accrued interest totaled $313,962 as of December 31, 2019.
These notes are in default.
The due
date of April 7, 2017, on a $50,000 promissory note with an
unaffiliated investor, was extended to April 7, 2019. The note and
accrued interest can be converted into our common stock at a
conversion rate of $0.75 per share at any time prior to the
repayment. This conversion price is not required to adjust for the
reverse stock split as per the note agreement. Accrued interest
totaled $23,986 as of December 31, 2019. The note is in
default.
On
March 9, 2017, an entity owned and controlled by our chief
executive officer agreed to provide up to $200,000 in working
capital. The note bears interest of 10% and is due and payable
within 90 days of demand. During the year ended December 31, 2017,
we received an additional $2,000 and repaid $25,000. As of December
31, 2019, the balance outstanding was $177,000, plus accrued
interest of $50,797.
During
the third quarter of 2017, we completed a $2,000,000 convertible
promissory note private placement offering. The terms of the notes
are as follows: (i) interest is payable at 6% per annum;
(ii) the notes are payable two years after purchase; and (iii)
all principal and interest on each note automatically converts on
the conversion maturity date into shares of our common stock at a
conversion price of $4.00 per share, as long as the closing share
price of our common stock on the trading day immediately preceding
the conversion maturity date is at least $4.00, as adjusted for
stock splits, stock dividends, reclassification, and the like. If
the price of our shares on such date is less than $4.00 per share,
the notes (principal and interest) will be repaid in full. During
2019, $15,000 in notes was repaid. As of December 31, 2019, the
outstanding balance for the remaining three notes was $65,000, plus
accrued interest of $9,599. These notes are in
default.
On
November 6, 2017, we entered into an agreement and promissory note
with JPF Venture Group, Inc. to loan up to $2,000,000 to us. The
terms of the note are as follows: (i) interest is payable at
10% per annum; (ii) all unpaid principal and all accrued and
unpaid interest is due and payable at the earliest of a resolution
of the Memphis litigation (as defined therein), December 31, 2018,
or when we are otherwise able to pay. During 2019, we repaid
$34,000. As of December 31, 2019, the outstanding balance was
$578,093 and the accrued interest was $141,717. This note is in
default.
In
December 2017, we entered into a series of unsecured promissory
notes and warrant purchase agreements with accredited investors.
These notes accrue interest at a rate of 10% per annum payable on a
quarterly basis and are not convertible into shares of our capital
stock. The notes are payable within five business days after
receipt of gross proceeds of at least $1,500,000 from L2 Capital,
LLC, an unaffiliated Kansas limited liability company (“L2
Capital”). We may prepay the notes in whole or in part,
without penalty or premium, on or before the maturity date of July
30, 2019. In connection with the issuance of the notes, for each
note purchased, the note holder received a warrant as
follows:
●
$10,000 note with a
warrant to purchase 2,000 shares
●
$20,000 note with a
warrant to purchase 5,000 shares
●
$25,000 note with a
warrant to purchase 6,500 shares
●
$30,000 note with a
warrant to purchase 8,000 shares
●
$40,000 note with a
warrant to purchase 10,000 shares
●
$50,000 note with a
warrant to purchase 14,000 shares
The
exercise price per share of the warrants is equal to 85% of the
closing price of our common stock on the day immediately preceding
the exercise of the relevant warrant, subject to adjustment as
provided in the warrant. The warrant includes a cashless net
exercise provision whereby the holder can elect to receive shares
equal to the value of the warrant minus the fair market value of
shares being surrendered to pay the exercise price. As of December
31, 2019, the balance of the outstanding loans was $979,156 and the
accrued interest was $164,645. During 2019, 98,000 warrants were
transferred from a warrant holder to JPF Venture Group Inc. These
warrants were issued in exchange for shares issued by JPF Venture
Group to the warrant holders. The warrant terms remain the same. As
of December 31, 2019, we have outstanding warrants to purchase
223,000 shares of common stock. As of the date of this report,
these notes are in default.
On
February 15, 2018, we entered into an agreement with L2 Capital for
a loan of up to $565,555, together with interest at the rate of 8%
per annum, which consists of up to $500,000 and a prorated original
issuance discount of $55,555 and $10,000 for transactional expenses
to L2 Capital. L2 Capital has the right at any time to convert all
or any part of the note into fully paid and nonassessable shares of
our common stock at the fixed conversion price, which is equal to
$0.50 per share; however,
at any time on or after the occurrence of any event of default
under the note, the conversion price will adjust to the lesser of
$0.50 or 65% multiplied by the lowest volume weighted average price
of the common stock during the 20-trading-day period ending, in L2
Capital’s sole discretion on each conversion, on either the
last complete trading day prior to the conversion date or the
conversion date. During the year ended December 31, 2018, we
received five tranches totaling $482,222. As of December 31, 2018,
we have issued warrants to purchase 56,073 shares of common stock
in accordance with a nonexclusive finder’s fee arrangement.
These warrants have a fair value of $13,280 based on the
Black-Scholes option-pricing model. The fair value was recorded as
a discount on the notes payable and is being amortized over the
life of the notes payable. As of December 31, 2018, we have fully
amortized $91,222 of the debt issuance cost and have recorded a
debt discount of $749,026 for the fair value of derivative
liability and fully amortized the debt discount. As of December 31,
2019, we have outstanding warrants to purchase 56,073 shares of
common stock. During the year ended December 31, 2019, we issued
1,936,192 shares of common stock to L2 Capital for the conversion
of a portion of our notes payable in the amount of $44,733. As of
December 31, 2019, the outstanding balance of the original loan was
$323,412, plus a default penalty and fees of $837,724, for a total
of $1,161,136, and accrued interest was $294,039. The note is in
default. On August 1, 2019, L2 Capital, LLC sold the outstanding
loan balance and accrued interest on our note to Oasis Capital,
LLC. The terms and conditions of the original note remain in place.
As of the date of this report, this note is in
default.
On
September 19, 2018, we executed a note payable for $10,000 with an
unrelated party that bears interest at 6% per annum, which is due
quarterly beginning as of September 30, 2018. The maturity date for
the note is three years after date of issuance. In addition, the
lender received warrants to purchase 2,000 shares of common stock
upon signing the promissory note. The warrant can be exercised at a
price per share equal to a 15% discount from the price of common
stock on the last trading day before such purchase. As of December
31, 2019, we have outstanding warrants to purchase 2,000 shares of
common stock. As of December 31, 2019, the balance outstanding was
$10,000 and the accrued interest was $780.
On
December 14, 2018, L2 Capital LLC purchased our note payable from
Collier Investments, LLC. The total consideration was $371,250,
including the outstanding note balance of $281,250, the accrued
interest of $33,750, and liquidated damages of $56,250. There was
also a default penalty of $153,123. In addition, we issued 400,000
shares of common stock to L2 Capital as commitment shares with a
fair value of $21,200 in connection with the purchase of the note.
We executed a replacement convertible note with L2 Capital in the
amount of $371,250 with an interest rate of 12% per annum. The
maturity date of the note is December 22, 2018. The holder of the
note can convert the note, or any portion of it, into shares of
common stock at any time after the issuance date. The conversion
price is 65% of the market price, which is defined as the lowest
trading price for our common stock during the 20-trading-day period
prior to the conversion date. As of December 31, 2018, we have
recorded a debt discount of $665,690 for the fair value of
derivative liability and fully amortized the debt discount. During
the year ended December 31, 2019, we issued 1,800,000 shares of
common stock to L2 Capital for the conversion of a portion of our
notes payable in the amount of $49,614. As of December 31, 2019,
the outstanding balance was $987,986, which includes a default
penalty and fees of $665,550, and the accrued interest was
$239,916. This note is in default.
On
January 2, 2019, we issued a series of promissory notes totaling
$310,000 to accredited investors. Proceeds from these notes were
used to support the administrative and legal expenses of our
lawsuit before the United District Court for the Western District
of Tennessee, Ocean Thermal Energy
Corporation v. Robert Coe, el al., Case No.
2:17-cv-02343SHL-cgc, and any subsequent actions brought about as a
result of or in connection with this litigation. These notes are
secured against the proceeds from the litigation. The notes bear an
interest rate of 17%, plus one quarter of one percent of the actual
funds received from the litigation. The repayment of the principal,
accrued interest, and the percentage of the litigation funds
received will be paid immediately following the receipt of
sufficient funds from this litigation. As of December 31, 2019, the
outstanding balance of these loans is $310,000 and the accrued
interest was $50,783.
On
August 14, 2019, we executed a note payable for $26,200 with an
unrelated party that bears interest at 8% per annum and has a
maturity date of October 31, 2021. The note automatically converts
into 1,310,000 shares of our common stock either at the time the
closing sale price for our common stock is equal to or greater than
$1.00 per share, as adjusted for stock splits, stock dividends,
reclassification and the like, or at the maturity date of October
31, 2021, whichever occurs first. As of December 31, 2018, we have
recorded a debt discount of $21,211 for the fair value of
derivative liability and amortized $4,989 of the debt discount. As
of December 31, 2019, the balance outstanding was $26,200 and the
accrued interest was $796.
In the
fourth quarter of 2019, we issued a series of convertible
promissory notes to accredited investors which totaled $105,000 as
of December 31, 2019. Of the amount received as of December 31,
2019, $10,000 was from our chief executive officer and our
independent director. The notes bear simple interest on outstanding
principal at the rate of 8% per annum, computed on the basis of the
actual number of days elapsed in a year of 365 days. Each $5,000
loan automatically converts into 250,000 shares of our common
stock, either at the time the closing sale price for our common
stock is equal to or greater than $1.00 per share, as adjusted for
stock splits, stock dividends, reclassification and the like, or at
the maturity date of October 31, 2021, whichever comes first. As of
December 31, 2019, we have recorded a debt discount of $105,000 for
the fair value of derivative liability and amortized $9,441of the
debt discount. As of December 31, 2019, the total outstanding
balances of all these loans are $8,441, net of debt discount of
$86,559 to unrelated parties, and $1,000, net of debt discount of
$9,000 to related parties. The accrued interest was
$1,492.
In the
fourth quarter of 2019, we issued a series of convertible
promissory notes to accredited investors, which totaled $36,750 as
of December 31, 2019. Of the amount received, $10,000 was received
from our chief executive officer and our independent director. The
notes bear simple interest on outstanding principal at the rate of
8% per annum, computed on the basis of the actual number of days
elapsed in a year of 365 days. Each $5,000 loan automatically
converts into 250,000 shares of our common stock, either at the
time the closing sale price for our common stock is equal to or
greater than $1.00 per share, as adjusted for stock splits, stock
dividends, reclassification and the like, or at the maturity date
of January 2, 2022, whichever comes first. As of December 31, 2019,
we have recorded a debt discount of $36,750 for the fair value of
derivative liability and amortized $986 of the debt discount. As of
December 31, 2019, the total outstanding balance of these loans
were $694, net of debt discount of $26,056 to unrelated parties and
$292, net of debt discount of $9,708 to related parties. The
accrued interest was $163.
The
following convertible note and notes payable were outstanding at
December 31, 2019:
|
|
|
|
|
|
|
|
|
Related
Party
|
|
|
Date of Issuance
|
|
|
In Default
|
|
Principal at December 31, 2019
|
Discount at December 31, 2019
|
Carrying Amount at December 31, 2019
|
|
|
|
|
|
12/12/06
|
|
6.25%
|
Yes
|
58,670
|
4,555
|
-
|
4,555
|
-
|
-
|
4,555
|
-
|
|
12/01/07
|
|
7.00%
|
Yes
|
125,000
|
85,821
|
-
|
85,821
|
-
|
-
|
85,821
|
-
|
|
09/25/09
|
|
5.00%
|
Yes
|
50,000
|
50,000
|
-
|
50,000
|
-
|
-
|
50,000
|
-
|
|
12/23/09
|
|
7.00%
|
Yes
|
100,000
|
94,480
|
-
|
94,480
|
-
|
-
|
94,480
|
-
|
|
12/23/09
|
|
7.00%
|
Yes
|
25,000
|
23,619
|
-
|
23,619
|
-
|
-
|
23,619
|
-
|
|
12/23/09
|
|
7.00%
|
Yes
|
25,000
|
23,620
|
-
|
23,620
|
-
|
-
|
23,620
|
-
|
|
02/03/12
|
|
10.00%
|
Yes
|
1,000,000
|
1,000,000
|
-
|
1,000,000
|
|
-
|
1,000,000
|
-
|
|
08/15/13
|
|
10.00%
|
No
|
158,334
|
158,334
|
-
|
158,334
|
-
|
-
|
-
|
158,334
|
|
12/31/13
|
|
8.00%
|
Yes
|
290,000
|
130,000
|
-
|
130,000
|
-
|
-
|
130,000
|
-
|
|
04/01/14
|
|
10.00%
|
Yes
|
2,265,000
|
1,102,500
|
-
|
1,102,500
|
1,102,500
|
-
|
-
|
-
|
|
12/22/14
|
|
22.00% *
|
Yes
|
200,000
|
200,000
|
-
|
200,000
|
-
|
-
|
200,000
|
-
|
|
12/26/14
|
|
22.00% *
|
Yes
|
100,000
|
100,000
|
-
|
100,000
|
-
|
-
|
100,000
|
-
|
|
03/12/15
|
(1)
|
6.00%
|
No
|
394,380
|
394,380
|
-
|
394,380
|
394,380
|
-
|
-
|
-
|
|
04/07/15
|
|
10.00%
|
Yes
|
50,000
|
50,000
|
-
|
50,000
|
-
|
-
|
50,000
|
-
|
|
11/23/15
|
(1)
|
6.00%
|
No
|
50,000
|
50,000
|
-
|
50,000
|
50,000
|
-
|
-
|
-
|
|
02/25/16
|
(1)
|
6.00%
|
No
|
50,000
|
50,000
|
-
|
50,000
|
50,000
|
-
|
-
|
-
|
|
05/20/16
|
(1)
|
6.00%
|
No
|
50,000
|
50,000
|
-
|
50,000
|
50,000
|
-
|
-
|
-
|
|
10/20/16
|
(1)
|
6.00%
|
No
|
50,000
|
12,500
|
-
|
12,500
|
12,500
|
-
|
-
|
-
|
|
10/20/16
|
(1)
|
6.00%
|
No
|
12,500
|
12,500
|
-
|
12,500
|
12,500
|
-
|
-
|
-
|
|
12/21/16
|
(1)
|
6.00%
|
No
|
25,000
|
25,000
|
-
|
25,000
|
25,000
|
-
|
-
|
-
|
|
03/09/17
|
(1)
|
10.00%
|
No
|
200,000
|
177,000
|
-
|
177,000
|
177,000
|
-
|
-
|
-
|
|
07/13/17
|
|
6.00%
|
Yes
|
25,000
|
25,000
|
-
|
25,000
|
-
|
-
|
25,000
|
-
|
|
07/18/17
|
|
6.00%
|
Yes
|
25,000
|
25,000
|
-
|
25,000
|
-
|
-
|
25,000
|
-
|
|
07/26/17
|
|
6.00%
|
Yes
|
15,000
|
15,000
|
-
|
15,000
|
-
|
-
|
15,000
|
-
|
|
12/20/17
|
(2)
|
10.00%
|
Yes
|
979,156
|
979,156
|
|
979,156
|
-
|
-
|
979,156
|
-
|
|
11/06/17
|
|
10.00%
|
Yes
|
646,568
|
578,093
|
-
|
578,093
|
578,093
|
-
|
-
|
-
|
|
02/19/18
|
(3)
|
18.00%*
|
Yes
|
629,451
|
1,161,136
|
-
|
1,161,136
|
-
|
-
|
1,161,136
|
-
|
|
09/19/18
|
|
6.00%
|
No
|
10,000
|
10,000
|
-
|
10,000
|
-
|
-
|
-
|
10,000
|
|
12/14/18
|
|
24.00%*
|
Yes
|
474,759
|
987,986
|
-
|
987,986
|
-
|
-
|
987,986
|
-
|
|
01/02/19
|
(4)
|
17.00%
|
No
|
310,000
|
310,000
|
|
310,000
|
-
|
-
|
310,000
|
-
|
|
08/14/19
|
|
8.00%
|
No
|
26,200
|
26,200
|
21,211
|
4,989
|
-
|
-
|
-
|
4,989
|
|
(5)
|
|
8.00%
|
No
|
105,000
|
105,000
|
95,559
|
9,441
|
-
|
1,000
|
-
|
8,441
|
|
(6)
|
01/02/22
|
8.00%
|
No
|
36,750
|
36,750
|
35,764
|
986
|
-
|
292
|
-
|
694
|
|
|
|
|
|
$8,561,768
|
$8,053,630
|
$152,534
|
$7,901,096
|
$2,451,973
|
$1,292
|
$5,265,373
|
$182,458
|
(1)
Maturity
date is 90 days after demand.
(2)
Bridge
loans were issued at dates between December 2017 and May 2018.
Principal is due on the earlier of 18 months from the anniversary
date or the completion of L2 financing with a gross proceeds of a
minimum of $1.5 million.
(3)
L2
- Note was drawn down in five tranches between 02/16/18 and
05/02/18.
(4)
Loans
were issued from January 2, 2019 to March 23, 2019. Principal and
interest are due when funds are received from the litigation
between Ocean Thermal Energy Corporation vs., Robert Coe el
al.
(5)
Notes
were issued between 10/14/19 1nd 11/5/19. The notes bear an
interest rate of 8% and mature 10/31/21. They can be
converted into 250,000 shares of common stock. They can be
converted when the stock closing price reaches $1 or on the
maturity, whichever occurs first.
(6)
Notes
were issued between 12/9/19 and 12/31/19. The notes bear an
interest rate of 8% and mature 1/2/22. They can be
converted into 250,000 shares of common stock. They can be
converted when the stock closing price reaches $1 or on the
maturity, whichever occurs first.
The
following convertible notes and notes payable were outstanding at
December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
Date of Issuance
|
|
|
In Default
|
|
Principal at December 31, 2018
|
Discount at December 31, 2018
|
Carrying Amount at December 31, 2018
|
|
|
|
|
|
12/12/06
|
|
6.25%
|
Yes
|
58,670
|
9,379
|
-
|
9,379
|
-
|
-
|
9,379
|
-
|
|
12/01/07
|
|
7.00%
|
Yes
|
125,000
|
85,821
|
-
|
85,821
|
-
|
-
|
85,821
|
-
|
|
09/25/09
|
|
5.00%
|
Yes
|
50,000
|
50,000
|
-
|
50,000
|
-
|
-
|
50,000
|
-
|
|
12/23/09
|
|
7.00%
|
Yes
|
100,000
|
94,480
|
-
|
94,480
|
-
|
-
|
94,480
|
-
|
|
12/23/09
|
|
7.00%
|
Yes
|
25,000
|
23,619
|
-
|
23,619
|
-
|
-
|
23,619
|
-
|
|
12/23/09
|
|
7.00%
|
Yes
|
25,000
|
23,620
|
-
|
23,620
|
-
|
-
|
23,620
|
-
|
|
02/03/12
|
|
10.00%
|
Yes
|
1,000,000
|
1,000,000
|
-
|
1,000,000
|
|
-
|
1,000,000
|
-
|
|
08/15/13
|
|
10.00%
|
No
|
525,000
|
158,334
|
-
|
158,334
|
-
|
-
|
-
|
158,334
|
|
12/31/13
|
|
8.00%
|
Yes
|
290,000
|
130,000
|
-
|
130,000
|
-
|
-
|
130,000
|
-
|
|
04/01/14
|
|
10.00%
|
Yes
|
2,265,000
|
1,102,500
|
-
|
1,102,500
|
1,102,500
|
-
|
-
|
-
|
|
12/22/14
|
|
22.00%*
|
Yes
|
200,000
|
200,000
|
-
|
200,000
|
-
|
-
|
200,000
|
-
|
|
12/26/14
|
|
22.00%*
|
Yes
|
100,000
|
100,000
|
-
|
100,000
|
-
|
-
|
100,000
|
-
|
|
03/12/15
|
(1)
|
6.00%
|
No
|
394,380
|
394,380
|
-
|
394,380
|
394,380
|
-
|
-
|
-
|
|
04/07/15
|
|
10.00%
|
Yes
|
50,000
|
50,000
|
-
|
50,000
|
-
|
-
|
50,000
|
-
|
|
11/23/15
|
(1)
|
6.00%
|
No
|
50,000
|
50,000
|
-
|
50,000
|
50,000
|
-
|
-
|
-
|
|
02/25/16
|
(1)
|
6.00%
|
No
|
50,000
|
50,000
|
-
|
50,000
|
50,000
|
-
|
-
|
-
|
|
05/20/16
|
(1)
|
6.00%
|
No
|
50,000
|
50,000
|
-
|
50,000
|
50,000
|
-
|
-
|
-
|
|
10/20/16
|
(1)
|
6.00%
|
No
|
50,000
|
12,500
|
-
|
12,500
|
12,500
|
-
|
-
|
-
|
|
10/20/16
|
(1)
|
6.00%
|
No
|
12,500
|
12,500
|
-
|
12,500
|
12,500
|
-
|
-
|
-
|
|
12/21/16
|
(1)
|
6.00%
|
No
|
25,000
|
25,000
|
-
|
25,000
|
25,000
|
-
|
-
|
-
|
|
03/09/17
|
(1)
|
10.00%
|
No
|
200,000
|
177,000
|
-
|
177,000
|
177,000
|
-
|
-
|
-
|
|
07/13/17
|
|
6.00%
|
No
|
25,000
|
25,000
|
-
|
25,000
|
-
|
-
|
25,000
|
-
|
|
07/18/17
|
|
6.00%
|
No
|
25,000
|
25,000
|
-
|
25,000
|
-
|
-
|
25,000
|
-
|
|
07/26/17
|
|
6.00%
|
No
|
15,000
|
15,000
|
-
|
15,000
|
-
|
-
|
15,000
|
-
|
|
07/27/17
|
|
6.00%
|
No
|
15,000
|
15,000
|
-
|
15,000
|
-
|
-
|
15,000
|
-
|
|
12/20/17
|
(2)
|
10.00%
|
Yes**
|
979,156
|
979,156
|
24,435
|
954,721
|
-
|
-
|
954,721
|
-
|
|
11/06/17
|
|
10.00%
|
Yes
|
646,568
|
612,093
|
-
|
612,093
|
612,093
|
-
|
-
|
-
|
|
02/19/18
|
(3)
|
18.00%*
|
Yes
|
629,451
|
629,451
|
-
|
629,451
|
-
|
-
|
629,451
|
-
|
|
09/19/18
|
|
6.00%
|
No
|
10,000
|
10,000
|
-
|
10,000
|
-
|
-
|
-
|
10,000
|
|
12/14/18
|
|
|
Yes
|
524,373
|
524,373
|
-
|
524,373
|
-
|
-
|
524,373
|
-
|
|
|
|
|
$8,515,098
|
$6,634,206
|
$24,435
|
$6,609,771
|
$2,485,973
|
$-
|
$3,955,464
|
$168,334
|
(1)
Maturity
date is 90 days after demand.
(2)
Bridge
loans were issued at dates between December 2017 and May 2018.
Principal is due on the earlier of 18 months from the anniversary
date or the completion of L2 financing with a gross proceeds of a
minimum of $1.5 million.
(3)
L2
- Note was drawn down in five tranches between 02/16/18 and
05/02/18.
**
Partially
in default on December 31, 2018
Maturities of Long-Term Obligations for Five Years and
Beyond
The
minimum principal payments of convertible notes and notes payable
at December 31, 2019:
|
2020
|
$7,717,346
|
|
2021
|
141,200
|
|
2022
|
36,750
|
|
2023 and
thereafter
|
158,334
|
|
Total
|
$8,053,630
|
NOTE 5 – DERIVATIVE LIABILITY
We measure the fair value of our assets and
liabilities under the guidance of ASC 820, Fair Value Measurements and
Disclosures, which defines fair
value, establishes a framework for measuring fair value in
accordance with GAAP, and expands disclosures about fair value
measurements. ASC 820 does not require any new fair value
measurements, but its provisions apply to all other accounting
pronouncements that require or permit fair value
measurement.
We
identified conversion features embedded within convertible debt
issued. We have determined that the features associated with the
embedded conversion option should be accounted for at fair value as
a derivative liability. We have elected to account for these
instruments together with fixed conversion price instruments as
derivative liabilities as we cannot determine if a sufficient
number of shares would be available to settle all potential future
conversion transactions.
Following
is a description of the valuation methodologies used to determine
the fair value of our financial liabilities, including the general
classification of such instruments pursuant to the valuation
hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative
Liability
|
$3,032,056
|
$-
|
$-
|
$3,032,056
|
|
|
|
|
Derivative
liability as of December 31, 2018
|
$2,292,254
|
|
Fair value at the
commitment date for convertible instruments
|
98,385
|
|
Change in fair
value of derivative liability
|
762,944
|
|
Reclassification to
additional paid-in capital for financial instruments
|
|
|
that
ceased to be a derivative liability
|
(121,527)
|
|
Derivative
liability as of December 31, 2019
|
$3,032,056
|
The
fair value of the derivative liability was estimated using the
income approach and the Black-Scholes option-pricing model. The
fair values at the commitment and remeasurement dates for our
derivative liabilities were based upon the following management
assumptions:
|
|
|
|
|
|
|
Expected
dividends
|
0%
|
|
Expected
volatility
|
49.2% to
500.0%
|
|
Risk free interest
rate
|
1,48%to
1.66%
|
|
Expected term (in
years)
|
.025 to
3.81
|
NOTE 6 – STOCKHOLDERS’ EQUITY
Common Stock
For the
year ended December 31, 2018, we issued 673,345 shares of common
stock for services performed with a fair value of
$138,986.
For the
year ended December 31, 2018, we issued 2,300,000 shares of common
stock for financing to L2 Capital with a fair value of $106,905 in
cash, net of offering cost.
For the
year ended December 31, 2018, we issued 4,000,000 shares of common
stock to L2 Capital for the conversion of a portion of our notes
payable to L2 Capital in the amount of $114,078.
For the
year ended December 31, 2018, note holders elected to exercise
warrants to purchase 39,000 shares of common stock for $9,520 in
cash.
For the
year ended December 31, 2018, we sold 984,352 shares of common
stock for $58,980 in cash. This includes 240,840 shares of common
stock for $10,000 that were issued to our chief executive officer
and an independent director.
For the
year ended December 31, 2018, we issued 400,000 shares to L2
Capital as a commitment fee for $21,200 to purchase our outstanding
note payable from Collier Investments LLC.
For the
year ended December 31, 2019, we issued 3,736,192 shares of common
stock to L2 Capital LLC for the conversion of a portion of our
notes payable in the amount of $94,347.
Preferred Stock
On June
3, 2019, our board of directors approved the following issuances of
Preferred Stock:
Series B Preferred Stock
– We are authorized to issue 1,250,000 shares of Series B
Preferred Stock with a par value of $0.001. These shares will not
have voting rights alongside the common stock and each share of
Series B Preferred Stock will be convertible into ten shares of our
common stock. As of December 31, 2019, 518,750 shares of Series B
Preferred Stock have been issued for $207,500 in cash.
Series C Preferred Stock
– We are authorized to issue 2,700,000 shares of Series C
Preferred Stock with a par value of $0.001. These shares are a
one-time grant and will have voting rights alongside the common
stock. Each share of Series C Preferred Stock will be convertible
into five shares of our common stock. As of December 31, 2019,
2,300,000 shares of Series C Preferred Stock have been issued for
services with a fair value of $159,337. The shares were issued as
follows: 1,000,000 shares to our chief executive officer, 400,000
shares to our two independent directors, and 900,000 shares to
employees and consultants.
Warrants and Options
The
following table summarizes all warrants outstanding and exercisable
for the year ended December 31, 2019:
|
|
|
|
|
|
|
|
|
Balance at December
31, 2017
|
134,000
|
$0.27
|
|
Granted
|
255,073
|
$0.21
|
|
Exercised
|
(39,000)
|
$0.24
|
|
Forfeited
|
|
|
|
Balance at December
31, 2018
|
350,073
|
$0.18
|
|
Granted
|
-
|
-
|
|
Exercised
|
-
|
-
|
|
Forfeited
|
-
|
-
|
|
Balance at December
31, 2019
|
350,073
|
$0.18
|
|
Exercisable at
December 31, 2019
|
350,073
|
$0.18
|
During
the year ended December 31, 2019, no warrants were exercised. The
aggregate intrinsic value represents the excess amount over the
exercise price that optionees would have received if all options
had been exercised on the last business day of the period
indicated, based on our closing stock price of $0.0263 per share on
December 31, 2019. Of the total warrants outstanding on December
31, 2019, warrants to purchase 125,073 shares had no intrinsic
value, as the price of the stock on that date was lower than the
exercise price. The intrinsic value of warrants to purchase 225,000
shares on that date was $888.
NOTE 7 – INCOME TAX
The
Jobs Act significantly revised the U.S. corporate income tax law by
lowering the corporate federal income tax rate from 35% to
21%.
Our
ability to use our net operating loss carryforwards may be
substantially limited due to ownership change limitations that may
have occurred or that could occur in the future, as required by
Section 382 of the Code, as well as similar state provisions. These
ownership changes may limit the amount of net operating loss that
can be utilized annually to offset future taxable income and tax,
respectively. In general, an “ownership change” as
defined by Section 382 of the Code results from a transaction or
series of transactions over a three-year period resulting in an
ownership change of more than 50.0% of the outstanding stock of a
company by certain stockholders or public groups.
We have
not completed a study to assess whether an ownership change has
occurred or whether there have been multiple ownership changes
since we became a “loss corporation” under the
definition of Section 382. If we have experienced an ownership
change, utilization of the net operating loss carryforwards would
be subject to an annual limitation under Section 382 of the Code,
which is determined by first multiplying the value of our stock at
the time of the ownership change by the applicable long-term,
tax-exempt rate, and then could be subject to additional
adjustments, as required. Any limitation may result in expiration
of a portion of the net operating loss carryforwards before
utilization. Further, until a study is completed, and any
limitation known, no positions related to limitations are being
considered as an uncertain tax position or disclosed as an
unrecognized tax benefit. Any carryforwards that expire prior to
utilization as a result of such limitations will be removed from
deferred tax assets with a corresponding reduction of the valuation
allowance. Due to the existence of the valuation allowance, it is
not expected that any possible limitation will have an impact on
our results of operations or financial position.
A
reconciliation of income tax expense and the amount computed by
applying the statutory federal income tax rate of 18.9% to the
income before provision for income taxes is as
follows:
|
|
For the Years
Ended December 31
|
|
|
|
|
|
Statutory rate
applied to loss before income taxes
|
$(1,409,990)
|
$(2,276,031)
|
|
Increase (decrease)
in income taxes results from:
|
|
|
|
Nondeductible
permanent differences
|
259,070
|
806,885
|
|
Change
in valuation allowance
|
1,150,920
|
1,469,146
|
|
Income tax expense
(benefit)
|
$-
|
$-
|
Deferred income
taxes reflect the net tax effects of temporary differences between
the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes.
Significant components of our deferred tax assets and liabilities
are as follows:
|
|
For the Years
Ended December 31
|
|
|
|
|
|
Deferred tax
assets
|
$2,358,860
|
$2,358,860
|
|
Operating loss
carryforwards
|
9,068,070
|
7,917,151
|
|
Gross deferred tax
assets
|
11,426,930
|
10,276,011
|
|
Valuation
allowance
|
(11,426,930)
|
(10,276,011)
|
|
Net deferred income
tax asset
|
$-
|
$-
|
We have
net operating loss carryforwards for income tax purposes of
approximately $31,385,000. This loss is allowed to be offset
against future income. The tax benefits relating to all timing
differences have been fully reserved for in the valuation allowance
account due to the substantial losses incurred through December 31,
2019. The change in the valuation allowance for the years ended
December 31, 2019 and 2018, was an increase of $1,150,920 and
$1,469,146, respectively.
NOTE 8 – COMMITMENTS AND CONTINGENCIES
Commitments
On December 11,
2017, we entered into an equity purchase agreement with L2 Capital,
LLC, for up to $15,000,000. As provided in the agreement, we may
require L2 Capital to purchase shares of common stock from time to
time by delivering a “put” notice to L2 Capital
specifying the total number of shares to be purchased. L2 Capital
will pay a purchase price equal to 85% of the “market
price,” which is defined as the lowest traded price on the
OTCQB marketplace during the five consecutive trading days
following the “put date” or the date on which the
applicable shares are delivered to L2 Capital. The number of shares
may not exceed 300% of the average daily trading volume for our
common stock during the five trading days preceding the date on
which we deliver the applicable put notice. Additionally, such
amount may not be lower than $10,000 or higher than $1,000,000. L2
Capital has no obligation to purchase shares under this agreement
to the extent that such purchase would cause L2 Capital to own more
than 4.99% of our common stock. Upon the execution of this
agreement, we issued 1,714,285 shares of common stock valued at
$514,286 as a commitment fee in connection with the agreement. The
shares to be issued pursuant to this agreement were covered by a
Registration Statement on Form S-1 effective on January 29, 2018,
with a post-effective amendment effective April 15, 2019. During
year ended December 31, 2019, we did not execute any put options
with L2 Capital to purchase any shares of common
stock.
On June
26, 2017, we entered a nonexclusive finder’s arrangement with
Craft Capital Management LLC (“Craft”) in the event
that proceeds with a debt and/or equity transaction or to finance a
merger/acquisition and/or another transaction are arranged by
Craft. We have no obligation to consummate any transaction, and we
can choose to accept or reject any transaction in our sole and
absolute discretion. Upon the successful completion of a placement,
we will pay to Craft 8% of the gross proceeds from an equity
placement and 3% for a debt placement. In addition, we will issue
to Craft, at the time of closing, warrants with an aggregate
exercise price equal to 3% of the amount raised. As of December 31,
2019, we have issued warrants to purchase 56,073 shares of common
stock for L2 Capital equity transactions and warrants to purchase
69,000 shares of common stock for L2 Capital debt transactions for
a total outstanding of warrants to purchase 125,073 shares of
common stock, none of which has been exercised. These warrants have
a fair value of $0 based on the Black-Scholes option-pricing model
as the exercise price is higher than the share value of our common
stock on December 31, 2019. The warrants have exercise prices
ranging from $0.0425 to $0.25 per share and are exercisable for a
period of five years after the closing of the placement. If we, at
any time while these warrants are outstanding, sell or grant any
option to purchase or sell or grant any right to reprice, or
otherwise dispose of or issue any common stock or securities
entitling any person or entity to acquire shares of common stock,
at an effective price per share less than the then-exercise price,
then the exercise price will be reduced to equal the lower share
price, at the option of Craft. Such adjustment will be made
whenever such common stock is issued. We will notify Craft in
writing, no later than the trading day following the issuance of
any common stock, of the applicable issuance price or applicable
reset price, exchange price, conversion price, and other pricing
terms.
Litigation
From
time to time, we are involved in legal proceedings and regulatory
proceedings arising from operations. We establish reserves for
specific liabilities in connection with legal actions that
management deems to be probable and estimable.
On May
4, 2018, we reached a settlement of the claims at issue in
Ocean Thermal Energy Corp.
v. Robert Coe, et al., Case No. 2:17-cv-02343SHL-cgc, before
the United States District Court for the Western District of
Tennessee. Between May 30 and July 19, 2018, we received three
payments totaling $100,000 from the defendants. On August 8, 2018,
an $8 million judgment was entered against the defendants and in
our favor. On May 28, 2019, we further settled the claims at issue
with two of the defendants, Brett M Regal and his company, Trade
Base Sales, Inc., for $17,500,000, bringing the combined judgment
and settlement amount owed to us as being $25,500,000. On July 1,
2019, the United States District Judge for the Central District of
California (case number: 2:19-cv-05299-VAP-JPR), approved our
stipulated application for an order permitting us to levy on
property, including, but not limited to, certain gemstone and
mineral specimens, known as the “Ophir Collection,”
owned by judgment debtors Brett M. Regal and Trade Base Sales, Inc.
(“Regal Debtors”), and appointing a receiver to carry
out the levy on Regal Debtors’ property, such that it may be
sold (subject to further order of the court approving and
confirming such sales), to satisfy the $25,500,000 settlement and
judgment amounts in our favor. On August 15, 2019, the
court-appointed receiver notified the court that he had taken
custody, possession, and control of the “Ophir
Collection” and 350,000 pounds of unrefined gold and other
precious metal bearing ore. By order of the court, the receiver has
the authority to assign, sell, and transfer the debtor property.
The proceeds of any sales will be used to satisfy the judgment and
settlement agreement, less the amount needed to satisfy an existing
lien (currently estimated at approximately $10 million plus
attorneys’ fees) and receivership’s reasonable costs
and fees. This process is ongoing.
On May
21, 2019, Theodore T. Herman filed a complaint against us in
Theodore T. Herman v.
Ocean Thermal Energy Corporation, Case No. CI-19-04780, in
the Court of Common Pleas of Lancaster County, Pennsylvania,
asserting that he is entitled to payment on the promissory note
described in Note 4: Convertible Notes and Notes Payable. On July
1, 2019, we filed preliminary objections to the complaint, and
subsequently filed an answer and new matter on August 20, 2019, to
which the plaintiff filed a reply on September 9, 2019. We
will continue to defend our position that no further payment of
principal or interest on this note is owed.
On
August 22, 2018, Fugro USA Maine, Inc. (“Fugro”), filed
suit against us in Fugro
USA Marine, Inc. v. Ocean Thermal Energy Corp., Cause No.
2018-56396, in the District Court for Harris County, TX, 165th
Judicial District, seeking approximately $500,000 allegedly owed
for engineering services provided. We have filed an answer
contesting the amounts owed, which we contend are substantially
less than claimed by Fugro.
NOTE 9 – CONSULTING AGREEMENTS
On June
4, 2018, we entered into a consulting agreement to pay 20,000
shares of common stock when one of the conditions of the contract
was satisfied. Although this condition was satisfied on August 31,
2018, as of December 31, 2019, we have not issued the shares. As of
December 31, 2019, and 2018, we have accrued the share compensation
at fair value totaling $1,600.
On
August 14, 2018, we entered into a consulting agreement to pay
$40,000 by issuing shares of common stock. As of December 31, 2019,
we have not issued the shares and have accrued the
amount.
For the
year ended December 31, 2018, we issued 673,345 shares of common
stock for services performed with a fair value of $138,986. There
were no shares of common stock issued for services in
2019.
NOTE 10 – EMPLOYMENT AGREEMENTS
On
January 1, 2011, we entered into a five-year employment agreement
with our chief executive officer, which provides for successive
one-year term renewals unless it is expressly cancelled by either
party 100 days prior to the end of the term. Under the agreement,
our chief executive officer will receive an annual salary of
$350,000, a car allowance of $12,000, and company-paid health
insurance. The agreement also provides for bonuses equal to one
times his annual salary plus 500,000 shares of common stock for
each additional project that generates $25 million or more in
revenue to us. Our chief executive officer is entitled to receive
severance pay in the lesser amount of three years’ salary or
100% of the remaining salary if the remaining term is less than
three years. On September 15, 2017, an addendum was added to the
employment agreement stating that effective June 30, 2017, his
salary will be increased to $388,220 per year; that he will receive
interest at a rate of 8% on his accrued unpaid wages; and that the
term of employment agreement is extended for an additional five
years.
NOTE 11 – RELATED-PARTY TRANSACTIONS
For the
years ended December 31, 2019 and 2018, we paid rent of $120,000
and $120,000, respectively, to a company controlled by our chief
executive officer under an operating lease agreement.
On
January 18, 2018, Jeremy P. Feakins & Associates, LLC, an
investment entity owned by our chief executive, chief financial
officer, and a director, agreed to extend the due date for
repayment of a $2,265,000 note issued in 2014 to the earlier of
December 31, 2019, or the date of the financial closings of our
Baha Mar project (or any other project of $25 million or more),
whichever occurs first. On August 15, 2018, principal of $618,500
and accrued interest of $207,731 were converted to 826,231 shares
at $1.00 per share, which was ratified by a disinterested majority
of the board of directors. The conversion was recorded at
historical cost due to the related-party nature of the transaction.
As of December 31, 2019, the note balance was $1,102,500 and the
accrued interest was $629,047. This note is in
default.
On
March 9, 2017, we issued a promissory note payable of $200,000 to a
related party in which our chief executive officer is an officer
and director. The note bears interest of 10% and is due and payable
within 90 days after demand. During the year ended December 31,
2018, we received an additional $2,000 and repaid $25,000. The
outstanding balance was $177,000 and accrued interest was $50,797
as of December 31, 2019.
On
November 6, 2017, we entered into an agreement and promissory note
with JPF Venture Group, Inc. to loan up to $2,000,000 to us. The
terms of the note are as follows: (i) interest is payable at
10% per annum; (ii) all unpaid principal and all accrued and
unpaid interest is due and payable at the earliest of resolution of
the Memphis litigation (as defined therein), December 31, 2019, or
when we are otherwise able to pay. As of December 31, 2019, the
outstanding balance was $578,093 and the accrued interest was
$141,717. For the years ended December 31, 2019 and 2018, we repaid
$34,000 and $29,474 respectively. This note is in
default.
We
remain liable for the loans made to us by JPF Venture Group, Inc.
before the Merger. As of December 31, 2019, the outstanding balance
of these loans was $594,380 and the accrued interest was $163,488.
All of these notes are in default.
In
December 2018, Jeremy P. Feakins, our chief executive officer, made
two advances to us totaling $4,600. The total amount was repaid on
January 23, 2019.
For the
year ended December 31, 2018, we sold 240,840 shares of common
stock for $10,000 in cash to our chief executive officer and an
independent director.
On June
3, 2019, our board of directors approved the issuances of Series C
Preferred Stock. We issued 1,000,000 shares to our chief executive
officer and 400,000 shares to our two independent directors with a
fair value of $96,987.
On
October 20, 2016, we borrowed $12,500 from an independent director
pursuant to a promissory note. The terms of the note are as
follows: (i) interest is payable at 6% per annum;
(ii) the note is payable 90 days after demand; and
(iii) the payee is authorized to convert part or all of the
note balance and accrued interest, if any, into shares of our
common stock at the rate of one share for each $0.03 of principal
amount of the note. This conversion share price was adjusted to
$0.01384 for the reverse stock splits. As of December 31, 2019, the
outstanding balance was $12,500, plus accrued interest of
$2,515.
In
June, 2019, JPF Venture Group, Inc., a company in which our chief
executive officer is an officer and director, provided a short-term
advances totaling $32,000 to us for working capital. It was repaid
in two payments in the third quarter of 2019.
In the
fourth quarter of 2019, we issued a series of convertible
promissory notes to accredited investors. The notes bear simple
interest on outstanding principal at the rate of 8% per annum,
computed on the basis of the actual number of days elapsed in a
year of 365 days. Each $5,000 loan automatically converts into
250,000 shares of our common stock, either at the time the closing
sale price for our common stock is equal to or greater than $1.00
per share, as adjusted for stock splits, stock dividends,
reclassification and the like, or at the maturity date of October
31, 2021, whichever comes first. On October 14, 2019, we borrowed
$5,000 from Jeremy P. Feakins, our chief executive officer. As of
December 31, 2019, the outstanding balance of his loan was $5,000
and the accrued interest was $85. On October 14, 2019, we borrowed
$5,000 from an independent director. As of December 31, 2019, the
outstanding balance of his loan was $5,000 and the accrued interest
was $78 (see Note 4).
In the
fourth quarter of 2019, we issued a series of convertible
promissory notes to accredited investors. The notes bear simple
interest on outstanding principal at the rate of 8% per annum,
computed on the basis of the actual number of days elapsed in a
year of 365 days. Each $5,000 loan automatically converts into
250,000 shares of our common stock, either at the time the closing
sale price for our common stock is equal to or greater than $1.00
per share, as adjusted for stock splits, stock dividends,
reclassification and the like, or at the maturity date of January
2, 2022, whichever comes first. On December 9, 2019, we borrowed
$5,000 from Jeremy P. Feakins, our chief executive officer. As of
December 31, 2019, the outstanding balance of his loan was $5,000
and the accrued interest was $24. On December 9, 2019, we borrowed
$5,000 from independent director. As of December 31, 2019, the
outstanding balance of his loan was $5,000 and the accrued interest
was $24 (see Note 4).
NOTE 12 – SUBSEQUENT EVENTS
Subsequent to
December 31, 2019, we issued a series of convertible promissory
notes to accredited investors in the amounts of $250,000 to
unrelated parties, $5,000 to our chief executive officer, and
$5,000 to one of our independent directors. The notes bear interest
at 8% per annum. The maturity date for each note is January 2,
2022. Each note automatically converts into 250,000 shares of our
common stock either at the time the closing sale price for our
common stock is equal to or greater than $1.00 per share, as
adjusted for stock splits, stock dividends, reclassification and
the like, or at the maturity date of January 2, 2022, whichever
occurs first.