Certain information contained in the following discussion and analysis,
including information with respect to our plans, strategy, projections and
expected timeline for our business and related financing, includes
forward-looking statements. Forward-looking statements are estimates based upon
current information and involve a number of risks and uncertainties. Actual
events or results may differ materially from the results anticipated in these
forward-looking statements as a result of a variety of factors.
You should read "Risk Factors" and "Cautionary Statement on Forward-Looking
Statements" elsewhere in this Quarterly Report on Form 10-Q ("Quarterly Report")
and under similar headings in the Annual Report on Form 10-K for the year ended
December 31, 2020 (our "Annual Report") for a discussion of important factors
that could cause actual results to differ materially from the results described
in or implied by the forward-looking statements contained in the following
discussion and analysis.
The following information should be read in conjunction with our unaudited
condensed consolidated financial statements and accompanying notes included
elsewhere in this Quarterly Report. Our financial statements have been prepared
in accordance with GAAP. This information is intended to provide investors with
an understanding of our past performance and our current financial condition and
is not necessarily indicative of our future performance. Please refer to
"-Factors Impacting Comparability of Our Financial Results" for further
discussion. Unless otherwise indicated, dollar amounts are presented in
thousands.
Unless the context otherwise requires, references to ''Company,'' ''NFE,''
''we,'' ''our,'' ''us'' or similar terms refer to (i) prior to our conversion
from a limited liability company to a corporation, New Fortress Energy LLC and
its subsidiaries and (ii) following the conversion from a limited liability
company to a corporation, New Fortress Energy Inc. and its subsidiaries. When
used in a historical context that is prior to the completion of NFE's initial
public offering ("IPO"), "Company," "we," "our," "us" or like terms refer to New
Fortress Energy Holdings LLC, a Delaware limited liability company ("New
Fortress Energy Holdings"), our predecessor for financial reporting purposes.
Overview
We are a global integrated gas-to-power infrastructure company that seeks to use
natural gas to satisfy the world's large and growing power needs. We deliver
targeted energy solutions to customers around the world, thereby reducing their
energy costs and diversifying their energy resources, while also reducing
pollution and generating compelling margins. Our near-term mission is to provide
modern infrastructure solutions to create cleaner, reliable energy while
generating a positive economic impact worldwide. Our long-term mission is to
become one of the world's leading carbon emission-free independent power
providing companies. We discuss this important goal in more detail in the Annual
Report, "Items 1 and 2: Business and Properties" under "Toward a Carbon-Free
Future".
As an integrated gas-to-power energy infrastructure company, our business model
spans the entire production and delivery chain from natural gas procurement and
liquefaction to logistics, shipping, facilities and conversion or development of
natural gas-fired power generation. We currently source LNG from long-term
supply agreements with third party suppliers and from our own liquefaction
facility in Miami, Florida. We expect that control of our vertical supply chain,
from procurement to delivery of LNG, will help to reduce our exposure to future
LNG price variations and enable us to supply our existing and future customers
with LNG at a price that reinforces our competitive standing in the LNG market.
Our strategy is simple: we seek to procure LNG at attractive prices using
long-term agreements and through our own production, and we seek to sell natural
gas (delivered through LNG infrastructure) or gas-fired power to customers that
sign long-term, take-or-pay contracts.
Our Current Operations
Our management team has successfully employed our strategy to secure long-term
contracts with significant customers in Jamaica and Puerto Rico, including
Jamaica Public Service Company Limited ("JPS"), the sole public utility in
Jamaica, South Jamaica Power Company Limited ("SJPC"), an affiliate of JPS,
Jamalco, a bauxite mining and alumina producer in Jamaica, and the Puerto Rico
Electric Power Authority ("PREPA"), each of which is described in more detail
below. Our assets built to service these significant customers have been
designed with capacity to service other customers.
We currently procure our LNG either by purchasing from a supplier or by
manufacturing it in our Miami Facility. Our long-term goal is to develop the
infrastructure necessary to supply our existing and future customers with LNG
produced primarily at our own facilities, including our expanded delivery
logistics chain in Northern Pennsylvania (the "Pennsylvania Facility").
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Montego Bay Facility
The Montego Bay Facility serves as our supply hub for the north side of Jamaica,
providing natural gas to JPS to fuel the 145MW Bogue Power Plant in Montego Bay,
Jamaica. Our Montego Bay Facility commenced commercial operations in October
2016 and is capable of processing up to 740,000 gallons of LNG (61,000 MMBtu)
per day and features approximately 7,000 cubic meters of onsite storage. The
Montego Bay Facility also consists of an ISO loading facility that can transport
LNG to numerous on-island industrial users.
Old Harbour Facility
The Old Harbour Facility commenced commercial operations in June 2019 and is
capable of processing approximately six million gallons of LNG (500,000 MMBtu)
per day. The Old Harbour Facility supplies natural gas to the new 190MW Old
Harbour power plant (the "Old Harbour Power Plant") operated by SJPC. The Old
Harbour Facility is also supplying natural gas to our dual-fired combined heat
and power facility in Clarendon, Jamaica (the "CHP Plant"). The CHP Plant
supplies electricity to JPS under a long-term PPA. The CHP Plant also provides
steam to Jamalco under a long-term take-or-pay SSA. On March 3, 2020, the CHP
Plant commenced commercial operation under both the PPA and the SSA and began
supplying power and steam to JPS and Jamalco, respectively. In August 2020, we
began to deliver gas to Jamalco to utilize in their gas-fired boilers.
San Juan Facility
In July 2020, we finalized the development of the San Juan Facility. The San
Juan Facility is near the San Juan Power Plant and serves as our supply hub for
the San Juan Power Plant and other industrial end-user customers in Puerto Rico.
We have delivered natural gas used for the commissioning of PREPA's power plant
under the Fuel Sale and Purchase Agreement with PREPA since April 2020. See
"-Other Matters" for additional information regarding our San Juan Facility.
Miami Facility
Our Miami Facility began operations in April 2016. This facility has
liquefaction capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) per
day and enables us to produce LNG for sales directly to industrial end-users in
southern Florida, including Florida East Coast Railway via our train loading
facility, and other customers throughout the Caribbean using ISO containers.
Suape Development
On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key
permits and authorizations to develop an LNG terminal and up to 1.37GW of
gas-fired power at the Port of Suape in Brazil. On March 11, 2021, we acquired
100% of the outstanding shares of Pecém Energia S.A. ("Pecém") and Energetica
Camacari Muricy II S.A. ("Muricy"). These companies collectively hold certain
15-year power purchase agreements totaling 288 MW for the development of the
thermoelectric power plants in the State of Bahia, Brazil. We will seek to
obtain the necessary approvals from ANEEL and other relevant regulatory
authorities in Brazil to transfer the site for the power purchase agreements to
the Port of Suape and update the technical characteristics in order to develop
and plan to construct a 288MW gas-fired power plant and LNG import terminal at
the Port of Suape to provide LNG and natural gas to major energy consumers
within the port complex and across the greater Northeast region of Brazil.
Other Development Projects
We are in the process of developing an LNG regasification facility and power
plant at the Port of Pichilingue in Baja California Sur, Mexico (the "La Paz
Facility"). Initially, the La Paz Facility is expected to supply approximately
270,000 gallons of LNG (22,300 MMBtu) per day under an intercompany GSA for
approximately 100 MW of power supplied by gas-fired modular power units that we
plan to develop, own and operated, which may be increased to approximately
350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power. In
addition, we recently executed an agreement with CFEnergia for the supply of
natural gas to power plants located in Punta Prieta and Coromuel for an
estimated 250,000 gallons of LNG (20,700 MMBtu) per day.
We are also in the process of developing an LNG regasification facility and
power plant in Puerto Sandino, Nicaragua (the "Puerto Sandino Facility"). In
February 2020, we entered into a 25-year PPA with Nicaragua's electricity
distribution companies, and we are in the process of constructing an
approximately 300 MW natural gas-fired power plant that will consume
approximately 700,000 gallons of LNG (57,500 MMBtus) per day.
We are currently developing a modular floating liquefaction facility to provide
a low-cost supply of liquefied natural gas for our growing customer base. The
"Fast LNG" design pairs advancements in modular, midsize liquefaction technology
with jack up rigs or similar floating infrastructure to enable a much lower cost
and faster deployment schedule than today's floating liquefaction vessels. A
permanently moored FSU will serve as an LNG storage facility alongside the
floating liquefaction infrastructure, which can be deployed anywhere there is
abundant and stranded natural gas.
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Recent Developments: Hygo and GMLP Acquisitions
On April 15, 2021, the Company completed the previously announced acquisitions
of Hygo Energy Transition Ltd. ("Hygo") and Golar LNG Partners LP ("GMLP");
referred to as the "Hygo Merger" and "GMLP Merger," respectively and,
collectively, the "Mergers". NFE paid $580 million in cash and issued 31,372,549
shares of Class A common stock to Hygo's shareholders in connection with the
Hygo Merger. NFE paid $3.55 per each common unit of GMLP outstanding and for
each of the outstanding membership interest of GMLP's general partner, totaling
$251 million.
As a result of the Hygo Merger we acquired one operating FSRU terminal in
Sergipe, Brazil (the "Sergipe Facility"), a 50% interest in a 1.5G GW power
plant in Sergipe, Brazil (the "Sergipe Power Plant"), as well as two other FSRU
terminals in development in Pará, Brazil (the "Barcarena Facility") and Santa
Catarina, Brazil (the "Santa Catarina Facility"). In addition, we acquired
Hygo's vessel fleet, which consists of the Golar Nanook, a newbuild FSRU moored
and in service at the Sergipe Facility, and two operating LNG carriers, the
Golar Celsius and the Golar Penguin, which may be converted into FSRUs.
As a result of the GMLP Merger we acquired a fleet of six FSRUs, four LNG
carriers and an interest in a floating liquefaction vessel, the Hilli, which
receives, liquefies and stores LNG at sea and transfers it to LNG carriers that
berth while offshore, each of which are expected to help support our existing
facilities and international project pipeline. The majority of the FSRUs in
GMLP's fleet are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan
under time charters. GMLP's uncontracted vessels are available for short term
employment in the spot market.
Cash consideration for the GMLP Merger was funded from proceeds from a private
offering of $1.5 billion aggregate principal amount of senior secured notes due
2026 (the "2026 Notes") completed on April 12, 2021. The 2026 Notes bear
interest at 6.50% per annum and were issued at an issue price equal to 100% of
principal. On April 15, 2021, we also entered into a $200 million senior secured
revolving facility (the "Revolving Facility"). The Revolving Facility has a term
of approximately five years and bears interest based on the three-month LIBOR
rate plus certain margins.
COVID-19 Pandemic
We are closely monitoring the impact of the novel coronavirus ("COVID-19")
pandemic on all aspects of our operations and development projects. We primarily
operate under long-term contracts with customers, many of which contain fixed
minimum volumes that must be purchased on a "take-or-pay" basis. We have
continued to invoice our customers for these fixed minimum volumes even in cases
when our customer's consumption has decreased. We have not changed our payment
terms with these customers, and there has not been deterioration in the timing
or volume of collections.
Based on the essential nature of the services we provide to support power
generation facilities, our development projects have not currently been
significantly impacted by responses to the COVID-19 pandemic. We remain
committed to prioritizing the health and well-being of our employees, customers,
suppliers and other partners. We have implemented policies to screen employees,
contractors, and vendors for COVID-19 symptoms upon entering our development
projects, operations and office facilities. For the three months ended March 31,
2021, we have incurred approximately $0.4 million for safety measures introduced
into our operations and other responses to the COVID-19 pandemic.
We are actively monitoring the spread of the pandemic and the actions that
governments and regulatory agencies are taking to fight the spread. We have not
experienced significant disruptions in development projects and daily operations
from the COVID-19 pandemic; however, there are important uncertainties including
the scope, severity and duration of the pandemic, the actions taken to contain
the pandemic or mitigate its impact, and the direct and indirect economic
effects of the pandemic and containment measures. We do not currently expect
these factors to have a significant impact on our results of operations,
liquidity or financial position, or our development budgets or timelines.
Other Matters
We received an order from FERC on June 18, 2020, which asked us to explain why
our San Juan Facility is not subject to FERC's jurisdiction under section 3 of
the Natural Gas Act. While we do not believe that the San Juan Facility is
jurisdictional, we provided our reply to FERC on July 20, 2020 and requested
that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San
Juan Facility does fall under FERC jurisdiction. FERC directed us to file an
application for authorization to operate the San Juan Facility within 180 days
of the order, but also found that allowing operation of the San Juan Facility to
continue during the pendency of an application is in the public interest. FERC
also concluded that no enforcement action against us is warranted, presuming we
comply with the requirements of the order. Parties to the proceeding, including
the Company, have sought rehearing of the March 19, 2021 FERC order and such
rehearing requests remain pending before FERC. FERC's orders in the proceeding
would be subject to subsequent judicial review.
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Results of Operations - Three Months Ended March 31, 2021 compared to Three
Months Ended March 31, 2020
Three Months Ended March 31,
2021 2020 Change
Revenues
Operating revenue $ 91,196 $ 63,502 $ 27,694
Other revenue 54,488 11,028 43,460
Total revenues 145,684 74,530 71,154
Operating expenses
Cost of sales 96,671 68,216 28,455
Operations and maintenance 16,252 8,483 7,769
Selling, general and administrative 45,181 28,538 16,643
Contract termination charges and loss on mitigation sales - 208 (208 )
Depreciation and amortization 9,890 5,254 4,636
Total operating expenses 167,994 110,699 57,295
Operating loss (22,310 ) (36,169 ) 13,859
Interest expense 18,680 13,890 4,790
Other (income) expense, net (604 ) 611 (1,215 )
Loss on extinguishment of debt, net - 9,557 (9,557 )
Loss before taxes (40,386 ) (60,227 ) 19,841
Tax (benefit) (877 ) (4 ) (873 )
Net loss $ (39,509 ) $ (60,223 ) $ 20,714
Revenues
Operating revenue from the sale of LNG, natural gas or outputs from our natural
gas-fired power generation facilities increased $27,694 for the three months
ended March 31, 2021 as compared to the three months ended March 31, 2020. The
increase was primarily driven by increases in volumes sold from the Old Harbour
Facility, including volumes utilized in the CHP Plant which commenced commercial
operations during March 2020:
• For the three months ended March 31, 2021, we recognized $51,644 of revenue
from volumes sold at the Old Harbour Facility, as compared to $35,777 for the
three months ended March 31, 2020, including additional revenue of $16,830 from
natural gas utilized in the CHP Plant and Jamalco's boilers. For the three
months ended March 31, 2021, the volume delivered to the Old Harbour Facility
was 53.0 million gallons (4.4 TBtu). For the three months ended March 31, 2020,
the volume delivered to the Old Harbour Facility was 42.1 million gallons (3.5
TBtu). The increase in volumes from sales to the Old Harbour Facility was
primarily due to volumes delivered to the CHP Plant and Jamalco's boilers
increasing by 15.7 million gallons (1.3 TBtu) to 25.5 million gallons (2.1
TBtu) from 9.8 million gallons (0.8 TBtu) in the three months ended March 31,
2020.
• Revenue from the delivery of power and steam, which began during March 2020,
under our contracts with JPS and Jamalco of $7,136 for the three months ended
March 31, 2021 as compared to $1,731 in revenue for the three months ended
March 31, 2020.
Operating revenue was also impacted by operations at our Montego Bay Facility.
Sales at the Montego Bay Facility increased by $1,956 from $22,823 for the three
months ended March 31, 2020 to $24,779 for the three months ended March 31,
2021. The increase in sales at the Montego Bay Facility was primarily due to an
increase in sales to industrial end-user customers, offset by a minor decrease
in consumption by the Bogue Power Plant. Volumes delivered at the Montego Bay
Facility remained relatively consistent for the three months ended March 31,
2021 as compared to the three months ended March 31, 2021, increasing by 0.1
million gallons (0.0 TBtu) from 23.5 million gallons (2.0 TBtu) during the three
months ended March 31, 2020 to 23.6 million gallons (2.0 TBtu) during the three
months ended March 31, 2021.
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Other revenue includes revenue from development services, which is recognized
from the construction, installation and commissioning of equipment to transform
customers' facilities to operate utilizing natural gas or to allow customers to
receive power or other outputs from our power generation facilities, and such
services are included within certain long-term contracts to supply these
customers with natural gas or outputs from our natural gas-fired facilities.
Other revenue increased $43,460 for the three months ended March 31, 2021 as
compared to the three months ended March 31, 2020, and the increases were due to
an increase in revenue for development services in Puerto Rico for the three
months ended March 31, 2021, including gas used by our customer for testing and
commissioning their assets. Development services revenue recognized in the three
months ended March 31, 2021 included $45,618 for the customer's use of 48.7
million gallons (4.0 TBtu) of natural gas as part of commissioning their
assets. The increase was partially offset by a decrease in development services
revenue of $1,033 related to conversion of the customer's infrastructure within
the San Juan Power Plant.
Cost of sales
Cost of sales includes the procurement of feedgas or LNG, as well as shipping
and logistics costs to deliver LNG or natural gas to our facilities, power
generation facilities or to our customers. Our LNG and natural gas supply are
purchased from third parties or converted in our Miami Facility. Costs to
convert natural gas to LNG, including labor, depreciation and other direct costs
to operate our Miami Facility are also included in Cost of sales.
Cost of sales increased $28,455 for the three months ended March 31, 2021 as
compared to the three months ended March 31, 2020.
Cost of LNG purchased from third parties for sale to our customers or delivered
for commissioning of our customer's assets in Puerto Rico increased $22,454 for
the three months ended March 31, 2021 as compared to the three months ended
March 31, 2020. The increase was primarily attributable to an 89% increase in
volumes delivered, inclusive of volumes delivered from our Miami Facility,
compared to the three months ended March 31, 2020, partially offset by the
decrease in LNG cost. The weighted-average cost of LNG purchased from third
parties and delivered decreased from $0.67 per gallon ($8.10 per MMBtu) for the
three months ended March 31, 2020 to $0.51 per gallon ($6.17 per MMBtu) for the
three months ended March 31, 2021. The weighted-average cost of our inventory
balance as of March 31, 2021 and December 31, 2020 was $0.55 per gallon ($6.63
per MMBtu) and $0.40 per gallon ($4.81 per MMBtu), respectively.
Charter costs increased Cost of sales by $2,241 for the three months ended March
31, 2021 as compared to the three months ended March 31, 2020. The increase was
attributable to an additional vessel in our fleet associated with our San Juan
Facility after our assets were placed in service in the third quarter of 2020,
as well as credits received in the first quarter of 2020 that did not recur in
the first quarter of 2021.
Operations and maintenance
Operations and maintenance includes costs of operating our Facilities, exclusive
of costs to convert that are reflected in Cost of sales. Operations and
maintenance for the three months ended March 31, 2021 was $16,252, which
increased $7,769 from $8,483 for the three months ended March 31, 2020. The
increase was primarily the result of operating facilities in the first quarter
of 2021 that were still in development or had just commenced commercial
operations in the first quarter of 2020. Operations and maintenance increased by
the costs of operating the San Juan Facility of $3,206 and an increase in the
cost to operate the CHP Plant of $1,844. Higher maintenance costs of $1,352 also
contributed to the increased operations and maintenance costs for the three
months ended March 31, 2021.
Selling, general and administrative
Selling, general and administrative includes compensation expenses for our
corporate employees, employee travel costs, insurance, professional fees for our
advisors and costs associated with development activities for projects that are
in initial stages and development is not yet probable.
Selling, general and administrative for the three months ended March 31, 2021,
was $45,181 which increased $16,643 from $28,538 for the three months ended
March 31, 2020. The increase was primarily attributable to $11,563 of
professional services costs and other costs associated with the Mergers. The
increase was also attributable to $4,050 of higher payroll costs associated with
increased headcount, partially offset by reductions to other administrative
costs.
Contract termination charges and loss on mitigation sales
Loss on mitigation sales for the three months ended March 31, 2021 and 2020 was
$0 and $208, respectively. In the first quarter of 2020, we incurred losses
associated with undelivered quantities of LNG under firm purchase commitments
due to storage capacity constraints. In these situations, our supplier will
attempt to sell the undelivered quantity through a mitigation sale, and the
losses incurred under the firm purchases are partially offset by this sale of
the undelivered amount to third parties for amounts lower than the contracted
price, which resulted in a loss of $208. We did not have such transactions
during the three months ended March 31, 2021.
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Depreciation and amortization
Depreciation and amortization increased $4,636 for the three months ended March
31, 2021. The increase was primarily due to the following:
• Increase in depreciation of $2,207 for the CHP Plant that went into service in
March 2020;
• Increase in depreciation of $2,385 for the San Juan Facility that went into
service in July 2020.
Interest expense
Interest expense for the three months ended March 31, 2021 was $18,680, which
increased $4,790 from $13,890 for the three months ended March 31, 2020,
primarily as a result of decreased capitalization of interest as both our CHP
Plant and our San Juan Facility were placed into service in 2020, as well as
higher principal balances outstanding during 2021. The increase in expense was
partially offset by a reduction to the amortization of financing costs.
Other (income) expense, net
Other income, net for the three months ended March 31, 2021 was $604, which
increased $1,215 from expense of $611 for the three months ended March 31, 2020,
primarily as a result of the unrealized loss on our investment in equity
securities of $2,400 in the first quarter of 2020 that did not recur in the
first quarter of 2021. We also recognized income from the change in fair value
of the derivative liability and equity agreement associated with our acquisition
of Shannon LNG.
Loss on extinguishment of debt, net
Loss on extinguishment of debt for the three months ended March 31, 2020 was
$9,557 as a result of the extinguishment of the Term Loan Facility in January
2020. We did not have such transactions during the three months ended March 31,
2021.
Tax (benefit)
We recognized a tax benefit for the three months ended March 31, 2021 of $877,
compared to tax benefit of $4 for the three months ended March 31, 2020. The
increase in benefit for the three months ended March 31, 2021 was primarily
driven by the release of a valuation allowance in a foreign jurisdiction
resulting in a discrete benefit of $3,010, partially offset by income tax
expense recorded for certain profitable foreign operations. The Company
determined that the valuation allowance should be released based on forecasted
pre-tax profits in this jurisdiction.
During 2020, the CHP Plant began operations and we placed our assets at the San
Juan Facility in service. Certain of our Jamaican operations had increased
earnings for the three months ended March 31, 2021 as compared to the three
months ended March 31, 2020 without any historical net operating losses to
offset additional tax expense. During the third quarter of 2020, we placed our
assets at the San Juan Facility into service, and since that point, we have
recognized tax expense in Puerto Rico at a preferential tax rate due to our tax
decree resulting in an effective tax rate lower than the U.S. federal income tax
rate. We continue to have valuation allowances in many of our foreign
jurisdictions and tax expense for earnings generated in many foreign
jurisdictions has been limited.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations and cash flows are not indicative of
results of operations and cash flows to be expected in the future, principally
for the following reasons:
• Our historical financial results do not include significant projects that have
recently been completed or are near completion. Our results of operations for
the three months ended March 31, 2021 include our Montego Bay Facility, Old
Harbour Facility, San Juan Facility, certain industrial end-users and our Miami
Facility. We are finalizing development of our La Paz Facility and our Puerto
Sandino Facility, and our current results do not include revenue and operating
results from these projects. Our current results also exclude other
developments, including, but not limited to, potential developements in Brazil
and the Ireland Facility.
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• Our historical financial results do not reflect new LNG supply agreements that
will lower the cost of our LNG supply through 2030. We currently purchase the
majority of our supply of LNG from third parties, sourcing approximately 97% of
our LNG volumes from third parties for the three months ended March 31, 2021, a
significant portion of which is under an LNG supply agreement signed in 2018.
During 2020, we also entered into four LNG supply agreements for the purchase
of approximately 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and
2030, resulting in expected pricing below the pricing in our previous long-term
supply agreement.
We also anticipate that the deployment of Fast LNG floating liquefaction
facilities will significantly lower the cost of our LNG supply and reduce our
dependence on third party suppliers.
• Our historical financial results do not include the acquisitions of Hygo and
GMLP as well as transaction and integration costs expected to be incurred
associated with these acquisitions. Upon completion of the acquisition of Hygo,
we acquired the Sergipe Facility, a 50% interest in the Sergipe Power Plant, as
well as the Barcarena Facility and the Santa Catarina Facility that are
currently in development. In addition, we acquired one FSRU in service at the
Sergipe Facility and two operating LNG carriers which may be converted into
FSRUs. Upon completion of the acquisition of GMLP, we acquired a fleet of six
FSRUs, four LNG carriers and an interest in a floating liquefaction vessel. The
results of operations of Hygo and GMLP will begin to be included in our
financial statements upon the closing of the acquisitions in the second quarter
of 2021. Our results of operations in 2021 will also include transaction costs
associated with these acquisitions as well as costs incurred to integrate the
operations of Hygo and GMLP into our business, which may be significant.
Liquidity and Capital Resources
We believe we will have sufficient liquidity from proceeds from recent
borrowings, access to additional capital sources and cash flow from operations
to fund our capital expenditures and working capital needs for the next 12
months. We expect to fund our current operations and continued development of
additional facilities through cash on hand, borrowings under our Revolving
Facility and cash generated from operations. We may also elect to generate
additional liquidity through future debt or equity issuances or debt
refinancings to fund developments and transactions. We have historically funded
our developments through proceeds from our IPO and debt and equity financing as
follows:
• In January 2020, we borrowed $800,000 under a credit agreement, and repaid our
prior term loan facility in full.
• In September 2020, we issued $1,000,000 of 2025 Notes and repaid all other
outstanding debt. No principal payments are due on the 2025 Notes until
maturity in 2025.
• In December 2020, we received proceeds of $263,125 from the issuance of
$250,000 of additional notes on the same terms as the 2025 Notes (subsequent to
this issuance, these additional notes are included in the definition of 2025
Notes herein).
• In December 2020, we issued 5,882,352 shares of Class A common stock and
received proceeds of $290,771, net of $1,221 in issuance costs.
On April 12, 2021, we issued $1.5 billion of 2026 Notes. The 2026 Notes bear
interest at 6.50% per annum and were issued at an issue price equal to 100% of
principal. No principal payments are due on the 2026 Notes until maturity in
2026. The Company used the net proceeds from this offering to fund the cash
consideration for the GMLP Merger and pay related fees and expenses. On April
15, 2021, we entered into the $200 million Revolving Facility that has a term of
approximately five years and bears interest based on the three-month LIBOR rate
plus certain margins.
We have assumed total expenditures for all completed and existing projects to be
approximately $1,239 million, with approximately $839 million having already
been spent through March 31, 2021. This estimate represents the expenditures
necessary to complete the La Paz Facility and the Puerto Sandino Facility,
expected expenditures to serve new industrial end-users and other planned
capital expenditures. We expect to be able to fund all such committed projects
with a combination of cash on hand, cash flows from operations and borrowings
under our Revolving Facility. We may also seek to fund our developments through
debt refinancings. We are currently exploring the potential refinancing of the
Golar Nanook with a sale-leaseback or similar financing. We cannot assure
whether any such refinancing will occur. Through March 31, 2021, we have spent
approximately $144 million to develop the Pennsylvania Facility. Approximately
$21 million of construction and development costs have been expensed as we have
not issued a final notice to proceed to our engineering, procurement and
construction contractors. Cost for land, as well as engineering and equipment
that could be deployed to other facilities and associated financing costs of
approximately $123 million, has been capitalized.
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Certain of the debt facilities of each of Hygo and GMLP or their respective
subsidiaries remained outstanding following the closing of the Mergers. The
following is a description of the debt facilities for each of Hygo and GMLP that
remain outstanding following the closing of the Mergers. In the future, we will
need to repay or refinance this additional indebtedness which could adversely
affect our liquidity and capital resources. There can be no assurances that we
will be able to refinance this indebtedness on favorable terms or at all.
Hygo Debt
Sergipe Debt Financing
To finance construction of the Sergipe Facility and the Sergipe Power Plant, in
April 2018, CELSE-Centrais Elétricas de Sergipe S.A. ("CELSE") signed financing
agreements with amounts made available by banks and multilateral organizations
throughout 2018 and 2019 (the "CELSE Facility"). As of December 31, 2020,
amounts outstanding and the effective interest rates under the CELSE Facility
were as set forth below. Principal and interest payments are due each October
and April, beginning October 2020. The CELSE Facility matures in April 2032.
Amount Effective
Credit facility (Real and USD in millions) Outstanding interest rate
IFC
R$ 844.9 ($156.8) 9.79 %
Inter-American Development Bank R$ 694.6 ($128.9) 9.69 %
IDB Invest $ 38.0 6.35 %
IDB China Fund $ 50.0 6.35 %
Also in April 2018, CELSE issued debentures in the aggregate principal amount of
R$3,370.0 million (net proceeds of $874 million), due April 2032, bearing
interest at a fixed rate of 9.85% (the "CELSE Debentures"). As of December 31,
2020, the balance of the CELSE Debentures was R$2,571.0 million ($477.3
million). Interest is payable on the CELSE Debentures semi-annually on each
April 15 and October 15, beginning on October 15, 2018. The CELSE Debentures are
amortized and repaid in 24 consecutive semi-annual installments on each of April
15 and October 15, commencing on October 15, 2020.
The indenture governing the CELSE Debentures contains covenants that: (i)
requires CELSE to maintain a historical debt service coverage ratio for a twelve
month period on or after March 31, 2021 of no less than 1.10 to 1.00; (ii)
prohibit certain restricted payments; (iii) limit the ability of CELSE from
creating any liens or incurring additional indebtedness; (iv) prohibit certain
fundamental changes; (v) limit the ability of CELSE to transfer or purchase
assets; (vi) prohibit certain affiliate transactions; (vii) limit the ability of
CELSE to make change orders or give other directions under the documents related
to the construction and operation of the project in certain circumstances;
(viii) limit the ability of CELSE to enter into additional contracts; (ix) limit
CELSE's operating expenses and capital expenditures; and (x) prohibit CELSE from
transferring, purchasing or otherwise acquiring any portion of the CELSE
Debentures, other than pursuant to the exercise of the put option.
On April 12, 2018, CELSEPAR-Centrais Elétricas de Sergipe Participações S.A.
("CELSEPAR") entered into a Standby Guarantee and Credit Facility Agreement with
GE Capital EFS Financing, Inc. ("GE Capital"), as lender, and Ebrasil Energia
Ltda. ("Ebrasil") and Golar Power Brasil Participações S.A ("Golar Brazil"),
each as sponsor (the "GE Credit Facility"). Pursuant to the GE Credit Facility,
GE Capital agreed to provide $120.0 million in credit support in respect of
CELSEPAR's obligation to make certain contingent equity contributions to CELSE.
Amounts disbursed under the GE Credit Facility accrue interest at a fixed rate
of LIBOR plus a margin of 11.4% and are payable on May 30 and November 30 each
year, beginning on May 30, 2021. The GE Credit Facility matures on November 30,
2024. As of December 31, 2020, there was R$689.4 million ($132.0 million)
outstanding under the GE Credit Facility. The GE Credit Facility includes
covenants and events of default that are customary for similar transactions.
Debenture Loan
On September 10, 2019, Hygo's subsidiary, Golar Brazil issued debentures in the
aggregate principal amount of R$300.0 million ($55.7 million) due September
2024, bearing interest at a rate equal to the one-day interbank deposit futures
rate in Brazil plus 2.65% (the "Debentures"). The offering resulted in net
proceeds to Golar Brazil, after deducting applicable discounts and commissions
and offering expenses, of R$295.0 million ($54.8 million). Interest is payable
on the Debentures semi-annually on each September 13 and March 13, beginning on
September 13, 2020. Principal due under the Debentures is amortized
semi-annually on each September 13 and March 13, beginning September 13, 2020.
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Golar Nanook Leaseback and Credit Facility
In September 2018, Golar FSRU8 Corp., a corporation organized in the Marshall
Islands, as subsidiary of Hygo, entered into a sale and leaseback transaction
with Compass Shipping 23 Corporation Limited in respect of the Golar Nanook (the
"Nanook Leaseback"). In September 2018, Compass Shipping 23 Corporation Limited,
the owner of the Golar Nanook, entered into a twelve-year, $277 million credit
facility (the "Nanook Facility"). Although we have no control over the funding
arrangements of Compass Shipping 23 Corporation Limited, we expect to be the
primary beneficiary of the Golar Nanook and therefore expect to consolidate the
Nanook Facility in our financial results. The Nanook Facility bears interest at
LIBOR plus a margin equal to 3.5% and is repayable in a balloon payment on
maturity. The Nanook Facility matures in September 2030.
The Golar Nanook is part of the Sergipe Facility. The terminal's assets consist
of (i) our FSRU, the Golar Nanook, which is under a 25-year bareboat charter
with CELSE (the "Sergipe FSRU Charter"), (ii) specialized mooring infrastructure
and (iii) a dedicated 8 kilometer pipeline which connects to the
adjacent Sergipe Power Plant. The Golar Nanook is financed through a twelve year
sale-leaseback transaction with the right and obligation to repurchase the
vessel at the end of the lease period. The balance of the infrastructure as well
as our interest in the Sergipe Power Plant is owned through our joint venture,
CELSEPAR.
The Golar Nanook operates under a 25-year bareboat charter with CELSE (the
"Sergipe FSRU Charter"). Pursuant to the Sergipe FSRU Charter, the Golar
Nanook generates approximately $44 million per year in bareboat charter
earnings, indexed to the Consumer Price Index ("CPI"), with operating
expenditures passed through to CELSE.
Pursuant to the terms of the Sergipe FSRU Charter, we expect total revenues less
estimated operating costs, without adjusting for inflation, of $1.1 billion over
the 25-year term. The charter terminates on December 31, 2044. In addition to
the charter, we expect to generate incremental revenue in the Sergipe Facility
from downstream customers. The Sergipe Facility is capable of processing up to
790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. We expect the
terminal to utilize approximately 230,000 MMBtu/d (30% of the terminal's maximum
regasification capacity) to provide natural gas to the Sergipe Power Plant at
full dispatch.
CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant will
deliver power to 26 committed offtakers, including investment grade
counterparties, for a period of 25 years. These PPAs provide for guaranteed
annual capacity payments of R$1.6 billion at an expected contracted EBITDA
margin on gross revenue of 61% (calculated as total revenues less direct
operating expenditures (including typical G&A and O&M charges relating to such
arrangements) assuming zero dispatch and subject to standard adjustments for
inflation and taxes to be incurred). The fixed capacity payments are adjusted
annually for the Extended National Consumer Price Index (the "IPCA"), the
Brazilian inflation-targeting system, which has historically offset changes in
the exchange rate between the U.S. dollar and the Brazilian real. Annual
revenues less operating costs are expected to be R$1.1 billion. Based on the
terms of our PPAs, we expect total contracted revenues over the 25-year term,
without adjusting for inflation, of R$41.0 billion. We also expect to generate
incremental variable revenue during periods we elect to dispatch and sell power
from the facility.
Golar Penguin Leaseback and Credit Facility
In December 2019, Golar Hull M2023 Corp., a corporation organized in the
Marshall Islands, as subsidiary of Hygo, entered into a sale and leaseback
transaction with Oriental LNG 02 Limited in respect of the Golar Penguin (the
"Penguin Leaseback"). Payments are due quarterly in 24 installments of $1.89
million, with a balloon payment of approximately $68.0 million upon maturity.
The Penguin Leaseback also contains certain covenants that, among other things,
(i) require GLNG to maintain a consolidated net worth equal or greater to $450.0
million and maintain current assets equal to or greater than current liabilities
and (ii) require the guarantor to maintain free liquid assets with aggregate
value equal to or greater than $50.0 million. The Penguin Leaseback is
cross-collateralized with a vessel under a sale and leaseback transaction
between a subsidiary of GLNG and Oriental LNG 01 Limited, whereby a default
under one sale and leaseback transaction automatically results in a default
under the other. In connection with the Hygo Merger, a Supplemental Deed to the
Penguin Leaseback was executed pursuant to which the cross-collateralization and
related default were removed. The Supplemental Deed is effective subject to
certain conditions, including consent from the lenders to the Penguin Facility
(as defined below) set out therein.
In October 2020, Oriental LNG 02 Limited, the owner of the Golar Penguin,
entered into a financing agreement to refinance its existing $113.4 million loan
facility (the "Penguin Facility"). Although we have no control over the funding
arrangements of Oriental LNG 02 Limited, we expect to be the primary beneficiary
of the Golar Penguin and therefore expect to be required to consolidate the
Penguin Facility in our financial results. The Penguin Facility bears interest
at LIBOR plus a margin of 1.7% and is repayable in quarterly installments over a
term of approximately six years.
Golar Celsius Leaseback and Credit Facility
On March 3, 2020, Golar Hull M2026 Corporation, a corporation organized in the
Marshall Islands, as subsidiary of Hygo, entered into in a sale and leaseback
transaction with Noble Celsius Shipping Limited in respect of the Golar Celsius
(the "Celsius Leaseback").
In March 2020, Noble Celsius Shipping Limited, the owner of the Golar Celsius,
entered into a three-year loan facility for $118.2 million (the "Celsius
Facility"). The Celsius Facility is denominated in U.S. dollars and bears
interest at 4.0% and is repayable at the end of the three-year period. Although
we have no control over the funding arrangements of Noble Celsius Shipping
Limited, we expect to be the primary beneficiary of the Golar Celsius and
therefore expect to consolidate the Celsius Facility in our financial results.
GMLP Debt
Golar Eskimo Leaseback and Credit Facility
In November 2015, GMLP entered into a sale and leaseback transaction with a
subsidiary, Sea 23 Leasing Co. Limited ("Eskimo SPV") of China Merchants Bank
Leasing in respect of the Golar Eskimo (the "Eskimo Leaseback"). The Eskimo
Leaseback also contains certain covenants that, among other things and subject
to certain exceptions and qualifications require: (a) GMLP to maintain a minimum
level of liquidity of $30 million and consolidated net worth of $123.95 million,
(b) GMLP to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (c) GMLP to
maintain a minimum percentage of the value of the Golar Eskimo over the relevant
outstanding balances of 110%. The Eskimo Leaseback is cross-collateralized with
a vessel under a sale and leaseback transaction between a subsidiary of GLNG and
Sea 24 Leasing Co. Limited, whereby a default under one sale and leaseback
transaction automatically results in a default under the other.
In November 2015, Eskimo SPV, which is the legal owner of the Golar Eskimo,
entered into a long-term loan facility (the "Eskimo SPV Debt"). The facility
bears interest at a rate of LIBOR plus a margin. Although we have no control
over the funding arrangements of the Eskimo SPV, we will be the primary
beneficiary of the Golar Eskimo and therefore will be required to consolidate
the Eskimo SPV Debt in our financial results.
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In conjunction with the closing of the GMLP Merger, GMLP delivered an
irrevocable notice to terminate the Eskimo Leaseback and repurchase the Golar
Eskimo, and we will complete the repurchase in the third quarter of 2021.
Golar Hilli Leaseback
Golar Hilli Corporation ("Hilli Corp") is a party to a Memorandum of Agreement,
dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of
China State Shipbuilding Corporation ("Fortune"), pursuant to which Hilli Corp
has sold to and leased back from Fortune the Hilli under a 10-year bareboat
charter agreement (the "Hilli Leaseback"). GMLP's 50% share of Hilli Corp's
indebtedness of $778.5 million amounted to $389.3 million as of December 31,
2020.
Pursuant to the GMLP Guarantee, GMLP is required to comply with the following
covenants and ratios: (i) free liquid assets of at least $30 million throughout
the Hilli Leaseback period; (ii) a maximum net debt to EBITDA ratio for the
previous 12 months of 6.5:1; (iii) a consolidated tangible net worth of $123.95
million, and (iv) a minimum EBITDA to consolidated debt service for the previous
12 months of 1.20:1.
Series A Preferred Units
Distributions on the Preferred Units are payable out of amounts legally
available therefor at a rate equal to 8.75% per annum of the stated liquidation
preference. In the event of a liquidation, dissolution or winding up, whether
voluntary or involuntary, holders of Preferred Units will have the right to
receive a liquidation preference of $25.00 per unit plus an amount equal to all
accumulated and unpaid distributions thereon to the date of payment, whether
declared or not. At any time on or after October 31, 2022, the Preferred Units
may be redeemed, in whole or in part, at a redemption price of $25.00 per unit
plus an amount equal to all accumulated and unpaid distributions thereon on the
date of redemption, whether declared or not.
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