NEW FORTRESS ENERGY INC.
Certain information contained in this 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
"Part 1, Item 1A. Risk Factors" and "Cautionary Statement on Forward-Looking
Statements" elsewhere in this Annual Report on Form 10-K ("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 comparison of the years ended December 31, 2020 and 2019 can be found in our
Annual Report on Form 10K for the year ended December 31, 2020 located within
"Part II, Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations."
The following information should be read in conjunction with our audited
consolidated financial statements and accompanying notes included elsewhere in
this Annual 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 like 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. Unless the context
otherwise requires, references to "Company," "NFE," "we," "our," "us" or like
terms refer to (i) prior to the completion of Mergers, New Fortress Energy Inc.
and its subsidiaries, excluding Hygo Energy Transition Ltd. ("Hygo") and its
subsidiaries and Golar LNG Partners LP ("GMLP") and its subsidiaries, and (ii)
after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries,
including Hygo and its subsidiaries and GMLP and its subsidiaries.
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 this Annual Report, "Items 1 and 2: Business and Properties" under "Sustainability-Toward a Carbon-Free Future". OnApril 15, 2021 , we completed the acquisitions of Hygo and 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 . The Company also repaid certain outstanding debt facilities of GMLP in conjunction with closing the GMLP Merger. The results of Hygo and GMLP have been included in the Company's consolidated financial statements for the period subsequent to the Mergers. As a result of the Hygo Merger, we acquired a 50% interest in a 1.5GW power plant inSergipe, Brazil (the "Sergipe Power Plant") and its operating FSRU terminal inSergipe, Brazil (the "Sergipe Facility"), the Barcarena Facility and Power Plant, the Santa Catarina Facility and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. As a result of the GMLP Merger, we acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (the "Hilli"), each of which are expected to help support our existing facilities and international project pipeline. The majority of the FSRUs are operating inBrazil ,Indonesia ,Jamaica andJordan under time charters, and uncontracted vessels are available for short term employment in the spot market. Subsequent to the completion of the Mergers, our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships. 53
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Our Terminals and Infrastructure segment includes 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 inMiami, Florida . Leased vessels as well as the cost to operate our vessels that are utilized in our terminal or logistics operations are included in this segment. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allow us more optimally manage our LNG supply and acquired and leased fleet. The Terminals and Infrastructure segment includes all terminal operations inJamaica ,Puerto Rico ,Mexico andBrazil , including our interest in the Sergipe Power Plant. Our Ships segment includes all vessels acquired in the Mergers, which are leased to customers under long-term or spot arrangements, including the 25-year charter of Nanook with CELSE. The Company's investment inHilli LLC , owner and operator of the Hilli, is also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.
Our Current Operations - Terminals and Infrastructure
Our management team has successfully employed our strategy to secure long-term contracts with significant customers inJamaica andPuerto Rico , including Jamaica Public Service Company Limited ("JPS"), the sole public utility inJamaica ,South Jamaica Power Company Limited ("SJPC"), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer inJamaica , and thePuerto 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 Fast LNG and our expanded delivery logistics chain inNorthern Pennsylvania (the "Pennsylvania Facility") in addition to supplying our customers through long-term LNG contracts.
Montego Bay Facility
The Montego Bay Facility serves as our supply hub for the north side ofJamaica , providing natural gas to JPS to fuel the 145MW Bogue Power Plant inMontego Bay, Jamaica . Our Montego Bay Facility commenced commercial operations inOctober 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 is an offshore facility consisting of an FSRU that is capable of processing approximately six million gallons of LNG (500,000 MMBtus) per day. The Old Harbour Facility commenced commercial operations inJune 2019 and supplies natural gas to the 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 inClarendon ,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. InMarch 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. InAugust 2020 , we began to deliver gas to Jamalco to utilize in their gas-fired boilers.
San Juan Facility
Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in thePort of San Juan, Puerto Rico . The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers inPuerto Rico . We have delivered natural gas to PREPA's power plant under the Fuel Sale and Purchase Agreement with PREPA sinceApril 2020 .
Sergipe Power Plant and Sergipe Facility
As part of the Hygo Merger, we acquired a 50% interest in Centrais Elétricas de
Sergipe Participações S.A. ("CELSEPAR"), which owns CELSE, the owner and
operator of the Sergipe Power Plant. The Sergipe Power Plant, a 1.5GW combined
cycle power plant, receives natural gas from the Sergipe Facility through a
dedicated 8-kilometer pipeline. The Sergipe Power Plant is one of the largest
natural gas-fired thermal power stations in Latin America and was built to
provide electricity on demand throughout the Brazilian electric integrated
system, particularly during dry seasons when hydropower is unable to meet the
growing demand for electricity in the country. CELSE has executed multiple PPAs
pursuant to which the Sergipe Power Plant is delivering power to 26 committed
offtakers (utilities) for a period of 25 years. In any period in which power is
not being produced pursuant to the PPAs, we are able to sell merchant power into
the electricity grid at spot prices, subject to local regulatory approval.
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We also own expansion rights with respect to the Sergipe Power Plant, which are owned by Centrais ElétricasBarra dos Coqueiros S.A . ("CEBARRA"), a joint venture with Ebrasil, of which we own 75%. These rights include 190 acres of land and regulatory permits for two new power generation projects of 2.0GW in the aggregate. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. The Sergipe Facility is capable of processing up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG, and supplies approximately 230,000 MMBtu/d (30% of the Sergipe Facility's maximum regasification capacity) of natural gas to to the Sergipe Power Plant, at full dispatch.
Miami Facility
Our Miami Facility began operations inApril 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 southernFlorida , includingFlorida East Coast Railway via our train loading facility, and other customers throughout theCaribbean using ISO containers.
Our Current Operations - Ships
Our Ships segment includes six FSRUs and five LNGCs, which are leased to customers under long-term or spot arrangements, including a 25-year charter of Nanook with CELSE. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. We began to use one acquired LNGC in our terminal operations in the third quarter of 2021, and the results of operations of this vessel are no longer included in the Ships segment. The Company's investment inHilli LLC , owner and operator of the Hilli, is also included in the Ships segment.Hilli Corp , a wholly owned subsidiary ofHilli LLC , has a Liquefication Tolling Agreement ("LTA") withPerenco Cameroon S.A. and Société Nationale des Hydrocarbures under which the Hilli provides liquefaction services throughJuly 2026 . Under the LTA,Hilli Corp receives a monthly tolling fee, consisting of a fixed element of hire and incremental tolling fees based on the price of Brent crude oil.
Our Development Projects
La Paz Facility
InJuly 2021 , we began commercial operations at thePort of Pichilingue inBaja California Sur, Mexico (the "La Paz Facility"). Initially, we are supplying CFEnergia with natural gas to power plants located inPunta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day, and we are in commercial discussions with CFEnergia to increase the volumes and extend the tenor of agreements to further their transition to gas-fired power. TheLa Paz Facility is expected to supply approximately an additional 270,000 gallons of LNG (22,300 MMBtu) per day to our 100MW of power supplied by gas-fired modular power units (the "LaPaz Power Plant ") following the start of operations. Natural gas supply to the LaPaz Power Plant may be increased to approximately 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135MW of power.
Puerto Sandino Facility
Development of our offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, inPuerto Sandino ,Nicaragua (the "Puerto Sandino Facility") is ongoing and we expect to begin commercial operations at the Puerto Sandino Facility in 2022. We have entered into a 25-year PPA withNicaragua's electricity distribution companies. We expect to utilize approximately 695,000 gallons of LNG (57,500 MMBtu) per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement.
Barcarena Facility
The Barcarena Facility will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility will be capable of processing up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to supply gas to a new 605MW combined cycle thermal power plant to be located inPará, Brazil (the "Barcarena Power Plant"), which is supported by multiple 25-year power purchase agreement to supply electricity to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025. 55
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Santa Catarina Facility
The Santa Catarina Facility will be located on the southern coast ofBrazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtu per day and LNG storage capacity of up to 170,000 cubic meters. We are also developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inlandTransportadora Brasileira Gasoduto Bolivia-Brasil S.A. ("TBG") pipeline via an interconnection point in Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day.
Suape Facility
We are developing our LNG terminal in theState of Pernambuco, Brazil (the "Suape Facility" and, together with the Sergipe Facility, the Barcarena Facility and the Santa Catarina Facility, our "Brazil Facilities"). We intend for the Suape Facility to supply LNG to a 288MW thermoelectric power plant to be located in theState of Pernambuco, Brazil (the "Suape Power Plant", and together with the Sergipe Power Plant and the Barcarena Power Plant, the "Brazil Power Plants"). We have obtained certain key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at thePort of Suape , in the city of Ipojuca,State of Pernambuco, Brazil , pursuant to the purchase of CH4 Energia Ltda. onJanuary 12, 2021 . We own certain 15-year power purchase agreements totaling 288MW for the development of two thermoelectric power plants, in theState of Bahia, Brazil , following the acquisition of 100% of the outstanding shares of PecémEnergia S.A. ("Pecém") and Energética CamaçariMuricy II S.A. ("Muricy") onMarch 11, 2021 . As ofJanuary 2022 , we had commenced power sales under these power purchase agreements via forward selling agreements. We are seeking to obtain the necessary approvals from ANEEL and other relevant regulatory authorities inBrazil to transfer the site for the power purchase agreements to the Suape Facility, and to update the technical characteristics to develop and construct an initial 288MW gas-fired power plant and LNG import terminal at thePort of Suape , to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region ofBrazil . Ireland Facility We intend to develop and operate an LNG facility and power plant (the "Ireland Facility" and, together with the Jamaica Facilities, the San Juan Facility, the Brazil Facilities the La Paz Facility and the Puerto Sandino Facility, our "LNG Facilities") and a CHP plant on the Shannon Estuary, near Tarbert,Ireland (the "Ireland Power Plant" and, together with the LaPaz Power Plant , theNicaragua Power Plant and the Brazil Power Plants, the "Power Plants," and together with the LNG Facilities, the "Facilities"). We are in the process of obtaining final planning permission from An Bord Pleanála ("ABP") inIreland and we intend to begin construction of the Ireland Facility after we have obtained the necessary consents and secured contracts with downstream customers with volumes sufficient to support the development.
Fast LNG
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, semi-submersible 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.
Other Projects
We are in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target pricing or margins. Recent DevelopmentsCargo Sales SinceAugust 2021 , LNG prices have increased materially. We have supply commitments to secure LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. Due to this significant increase in market pricing of LNG, we have optimized our supply portfolio to sell a portion of these cargos in the market, and these sales have positively impacted our results for the third and fourth quarters of 2021. Cargo sales of 18.5 TBtus were completed in the third and fourth quarters of 2021, increasing our revenues and results of operations for the year endedDecember 31, 2021 . 56
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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, including
our marine operations acquired in the Mergers. Customers in our Terminals and
Infrastructure segment primarily operate under long-term contracts, many of
which contain fixed minimum volumes that must be purchased on a "take-or-pay"
basis. We continue to invoice our customers for 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.
Many of the vessels acquired in the Mergers operate under long-term contracts
with fixed payments. We are required to have adequate crewing aboard our vessels
to fulfill the obligations under our contracts, and we have implemented safety
measures to ensure that we have healthy qualified officers and crew. We monitor
local or international transport or quarantine restrictions limiting the ability
to transfer crew members off vessels or bring a new crew on board, and
restrictions in availability of supplies needed on board due to disruptions to
third-party suppliers or transportation alternatives, and we have not
experienced significant disruptions in our operations due to these measures or
restrictions.
Based on the essential nature of the services we provide to support power
generation facilities, our operations and 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 year ended
December 31, 2021 , we have incurred approximately $0.8 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, charter or terminal
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
OnJune 18, 2020 , we received an order fromFERC , which asked us to explain why our San Juan Facility is not subject toFERC's jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply toFERC onJuly 20, 2020 and requested thatFERC act expeditiously. OnMarch 19, 2021 FERC issued an order that the San Juan Facility does fall underFERC jurisdiction.FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which isSeptember 15, 2021 , 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, sought rehearing of theMarch 19, 2021 FERC order, andFERC denied all requests for rehearing in an order issued onJuly 15, 2021 . We have filed petitions for review ofFERC's March 19 andJuly 15 orders with theUnited States Court of the Appeals for theDistrict of Columbia Circuit . To date, no other party has sought review ofFERC's orders. While our petitions for review are pending, and in order to comply with theFERC's directive, onSeptember 15, 2021 we filed an application for authorization to operate the San Juan Facility, which remains pending. 57
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Results of Operations - Year Ended
Segment performance is evaluated based on segment operating margin and the tables below presents our segment information for the years endedDecember 31, 2021 and 2020: Year Ended December 31, 2021 Terminals and Consolidation (in thousands of $) Infrastructure?¹? Ships?²? Total Segment and Other?³? Consolidated Statement of operations: Total revenues $ 1,366,142$ 329,608 $ 1,695,750 $ (372,940 ) $ 1,322,810 Cost of sales 789,069 - 789,069 (173,059 ) 616,010 Vessel operating expenses 3,442 64,385 67,827 (16,150 ) 51,677 Operations and maintenance 92,424 - 92,424 (19,108 ) 73,316 Segment Operating Margin $ 481,207$ 265,223 $ 746,430 $ (164,623 ) $ 581,807 ?¹? Terminals and Infrastructure includes the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The losses attributable to the investment of$17,925 for the year endedDecember 31, 2021 are reported in income from equity method investments on the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market loss on derivative instruments of$2,788 for the year endedDecember 31, 2021 reported in Cost of sales. ?²? Ships includes the Company's effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of$32,368 for the year endedDecember 31, 2021 are reported in income from equity method investments on the consolidated statements of operations and comprehensive income (loss).
?³? Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derviative instruments.
Terminals and Infrastructure Segment
Year Ended December 31, 2021
(in thousands of $) 2021 2020 Change
Statement of operations:
Total revenues $ 1,366,142 $ 451,650 $ 914,492
Cost of sales 789,069 278,767 510,302
Vessel operating expenses 3,442 - 3,442
Operations and maintenance 92,424 47,581 44,843
Segment Operating Margin $ 481,207 $ 125,302 $ 355,905
Total revenue
Total revenue for the Terminals and Infrastructure Segment increased $914,492
for the year ended December 31, 2021 as compared to the year ended December 31,
2020 . The increase was primarily driven by the overall increase in price and
volumes delivered in the current period, the sale of cargos of LNG to third
parties outside of our terminal operations and the inclusion of incremental
revenue in our segment measure from CELSEPAR after the completion of the
Mergers. Our contracts with customers in this segment are primarily priced based
on the Henry Hub index, and there have been significant increases in this price
index in the second half of 2021, positively impacting our revenue. The average
Henry Hub index pricing used to invoice our customers increased by 85% for the
year ended December 31, 2021 as compared to the year ended December 31, 2020 .
Additionally, we recognized additional revenue from more volumes sold to the
PREPA San Juan Power Plant in Puerto Rico .
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The following tables summarize the volumes delivered in the year ended
Year Ended December 31,
(in millions of gallons) 2021 2020 Change
Old Harbour Facility 211.2 192.2 19.0
Montego Bay Facility 84.0 94.2 (10.2 )
San Juan Power Plant 184.0 129.5 54.5
Other 16.9 12.9 4.0
Total volumes delivered in the current period 496.1 428.8 67.3
Year Ended December 31,
(in TBtu) 2021 2020 Change
Old Harbour Power Plant 17.5 15.9 1.6
Montego Bay Facility 7.1 7.9 (0.8 )
San Juan Power Plant 14.9 10.7 4.2
Other 2.3 1.1 1.2Total volumes delivered in the current period 41.8 35.6
6.2
The Old Harbour Facility sold additional volumes in the year endedDecember 31, 2021 as compared to the year endedDecember 31, 2020 . Increases in revenue were further impacted by substantial increases to natural gas pricing. Revenue was impacted by operations at our Old Harbour Facility:
• Sales at the Old Harbour Facility increased by
year ended
The increase in revenue from the Old Harbour Facility was due to an increase in
the Henry Hub index used to invoice our customers as compared to the year ended
Plant.
• Revenue from the delivery of power and steam increased by
for the year ended
2021, which began during
• The increase in volumes delivered at the Old Harbour Power Plant was partially
offset by a decrease in consumption by the CHP Plant and Jamalco's boilers. The
Jamalco refinery experienced a fire in
been consumed by their boilers since this event. However, steam revenue has
been consistent with previous periods as our contract with Jamalco has take-or-pay provisions that allow us to invoice for minimum volumes.
Revenue was also impacted by operations at our Montego Bay Facility.
• Sales at the Montego Bay Facility increased by
ended
increase in revenue from the Montego Bay Facility was due to an increase in the
revenue from industrial end users offset the decrease in volumes consumed by
the Bogue Power Plant.
• The decrease in volumes delivered at the Montego Bay Facility of 10.2 million
gallons (0.8 TBtu) was driven by a reconfiguration of the
where our facility resides required by the port authority. During this
reconfiguration, we are unable to deliver volumes to the Bogue Power Plant; we
expect this reconfiguration to be completed in the first half of 2022.
Sales at the PREPA San Juan Power Plant increased by$61,921 from$129,753 for the year endedDecember 31, 2020 to$191,674 for the year endedDecember 31, 2021 . The increase was driven by additional volumes consumed at theSan Juan Power Plant, increasing by 54.5 million gallons (4.2 TBtu), as ourSan Juan Facility was not completed untilJuly 2020 .
Revenue from cargo sales was
Subsequent to the acquisition of our interest in the Sergipe Facility as part of the Mergers, our share of revenue from our investment in CELSEPAR was$299,168 for the year endedDecember 31, 2021 , which was primarily comprised of fixed capacity payments received under our PPAs. Revenue recognized from the operation of the Sergipe Power Plant was significantly increased in the third and fourth quarters of 2021 by emergency dispatch due to poor hydrological conditions inBrazil . Our proportionate share of revenue from the Sergipe Facility is included in this discussion as such revenue is included in our segment measure; in our consolidated statement of operations and comprehensive loss, we report the results from our investment in CELSEPAR as Income from equity method investments. 59
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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. Our LNG and natural gas supply are purchased from third parties or converted in ourMiami 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
• Cost of LNG purchased from third parties for sale to our customers increased
volumes delivered compared to the year ended
in LNG cost. The weighted-average cost of LNG purchased from third parties
increased from
31, 2020 to
2021.
• Cost of LNG from the sale of cargos in the market was
ended
Due to the significant increase in market pricing of LNG in the second half of
2021, we have optimized our supply portfolio to sell a portion of our committed
cargos in the market. The weighted-average cost of LNG from the sale of a portion of our cargos was$0.81 per gallon ($9.82 per MMBtu).
• Subsequent to the acquisition of the Sergipe Facility as part of the Mergers,
our share of Cost of sales from our investment in CELSEPAR was
year ended
power plant and costs of power to fulfill requirements under the PPAs.
The weighted-average cost of our LNG inventory balance to be used in our
Jamaican and Puerto Rican operations as of
Charter costs increased Cost of sales by$7,633 for the year endedDecember 31, 2021 as compared to the year endedDecember 31, 2020 . The increase was attributable to an additional vessel in our fleet associated with ourSan Juan Facility after our assets were placed in service in the third quarter of 2020, as well as an additional vessel lease that we assumed as part of the Mergers. These increases were partially offset by lower costs associated with the Freeze, that we now own as a result of the Mergers.
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 increased$44,843 for the year endedDecember 31, 2021 as compared to the year endedDecember 31, 2020 .
• The increase for the year ended
during the year ended
portion of the year ended
increased by the costs of operating the San Juan Facility and CHP Plant, and an
increase in payroll costs, maintenance costs, insurance costs and port fees.
• Subsequent to acquisition of the Sergipe Facility as part of the Mergers, our
share of Operations and maintenance from our investment in CELSEPAR was
for the year ended
related to the operation and services agreement for the Nanook, insurance costs
and costs for connecting to the transmission system.
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Ships Segment
Year Ended
(in thousands of $) December 31, 2021
Statement of operations:
Total revenues $ 329,608
Cost of sales -
Vessel operating expenses 64,385
Operations and maintenance -
Segment Operating Margin $ 265,223
Prior to the completion of the Mergers, we reported our results of operations in
a single segment. All the assets and operations that comprise the Ships segment
were acquired in the Mergers, and as such, there are no results of operations
prior to the completion of the Mergers during the second quarter of 2021, and
the results of operations for the Ships segment for the year ended December 31,
2021 represents eight and a half months of operations.
Revenue in the Ships segment is comprised of operating lease revenue under time
charters, fees for repositioning vessels as well as the reimbursement of certain
vessel operating costs. We have also recognized revenue related to the interest
portion of lease payments and the operating and service agreements in connection
with the sales-type lease of the Nanook. We include the interest income earned
under sales-type leases as revenue as amounts earned under chartering and
operating service agreements represent our ongoing ordinary business operations.
At the completion of the Mergers, five of the FSRUs and two LNGCs were on hire
under long-term charter agreements, and one LNGCs, the Grand, was operating in
the spot market. In the third quarter, the Grand, began to be utilized in our
terminal and logistics operations, and as such, the results of operations of the
Grand are included in the Terminals and Infrastructure segment from the third
quarter of 2021 onward. The Spirit and the Mazo continue to be in cold lay-up,
and no vessel charter revenue was generated from these vessels.
Two of the vessels acquired in the Mergers, the Celsius and the Penguin, have
participated in a pooling arrangement, which we refer to as the Cool Pool . Under
this arrangement, the pool manager markets participating vessels in the LNG
shipping spot market, and the vessel owner continues to be fully responsible for
the manning and technical management of their respective vessels. Revenue for
charters of our vessels in the Cool Pool is presented on a gross basis in
revenue, and our allocation of our share of the net revenues earned from the
other pool participants' vessels, which may be either income or expense
depending on the results of all pool participants, is reflected on a net basis
within Vessel operating expenses. The Penguin exited the Cool Pool in the third
quarter of 2021, and we have chartered this vessel to a third party outside of
the Cool Pool .
For the year ended December 31, 2021 , revenue recognized in the Ships segment
included $32,880 of interest income for the Nanook sales-type lease and $5,549
of revenue for operating services provided to CELSE. As all operations of the
Ships segment were acquired in the Mergers, the results of operations for the
Nanook for the year ended December 31, 2021 represents eight and a half months
of operations.
Our segment measure includes our proportionate share of the results of
operations of the Hilli. Our share of revenue from our investment in Hilli LLC
was $73,772 for the year ended December 31, 2021 which was primarily comprised
of fees received under the long-term tolling arrangement.
Vessel operating expenses
Vessel operating expenses includes direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter. For the year endedDecember 31, 2021 , we recognized$64,385 in Vessel operating expenses. As all operations of the Ships segment were acquired in the Mergers, Vessel operating expenses for the year endedDecember 31, 2021 represents eight and a half months of operations of each of the acquired vessels. 61
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Other operating results
Year Ended December 31,
(in thousands of $) 2021 2020 Change
Selling, general and administrative $ 199,881 $ 120,142 $ 79,739
Transaction and integration costs 44,671 4,028 40,643
Contract termination charges and loss on
mitigation sales - 124,114 (124,114 )
Depreciation and amortization 98,377 32,376 66,001
Total operating expenses 342,929 280,660 62,269
Operating income (loss) 238,878 (155,358 ) 394,236
Interest expense 154,324 65,723 88,601
Other (income) expense, net (17,150 ) 5,005 (22,155 )
Loss on extinguishment of debt, net 10,975 33,062 (22,087 ) Net income (loss) before income from equity method investments and income taxes
90,729 (259,148 ) 349,877
Income from equity method investments 14,443 - 14,443
Tax provision 12,461 4,817 7,644
Net income (loss) $ 92,711 $ (263,965 ) $ 356,676 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 screening costs associated with development activities for projects that are in initial stages and development is not yet probable. Selling, general and administrative increased$79,739 for the year endedDecember 31, 2021 , as compared to the year endedDecember 31, 2020 . The increase was primarily attributable to$33,059 of higher payroll costs associated with increased headcount for the year endedDecember 31, 2021 . Subsequent to the Mergers, we now have employees that were part of Hygo's operations; we have also hired additional employees to support our larger organization, including personnel to support additional development projects. In the fourth quarter of 2021, due to the significant impact of cargo sales on our results of operations, we determined that the performance metric associated with our performance share units granted in 2020 was probable of vesting, and we recognized$30,467 of share-based compensation expense. We have incurred higher office lease, insurance and IT expenses associated with additional office space, and our travel and entertainment expenses have increased due to the relaxation of travel restrictions that were in place for much of 2020 due to COVID-19 pandemic. These costs increased our Selling, general and administrative by$10,918 .
Transaction and integration costs
For the year endedDecember 31, 2021 , we incurred$44,671 for transaction and integration costs, as compared to$4,028 for the year endedDecember 31, 2020 . As part of arranging financing for the Mergers, we incurred$15,000 in bridge financing commitment fees. We issued the 2026 Notes to pay for a portion of the consideration for the Mergers and did not utilize the commitments under the bridge financing, and as such, the fees were expensed with the termination of the bridge financing commitment letter in the second quarter of 2021. We also incurred$3,978 of costs related to the settlement of a contractual indemnification obligation under a pre-existing lease arrangement prior to the GMLP Merger. The remaining transaction and integration costs were incurred in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs.
For the year ended
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Contract termination charges and loss on mitigation sales
Loss on mitigation sales for the year endedDecember 31, 2020 was$124,114 . InJune 2020 , we executed an agreement to terminate our obligation to purchase LNG from our supplier for the remainder of 2020 in exchange for a payment of$105,000 , and we recognized this cancellation charge during the second quarter of 2020. We terminated our obligation in the second quarter of 2020 to both take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs. Additionally, in the second quarter of 2020, we experienced lower than expected consumption by some of our customers, primarily as a result of unplanned maintenance at one of our customer's facilities inJamaica . As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of$18,906 on the sale of this cargo that was recognized during the second quarter of 2020. We did not have such transactions during the year endedDecember 31, 2021 .
Depreciation and amortization
Depreciation and amortization increased$66,001 for the year endedDecember 31, 2021 as compared to the year endedDecember 31, 2020 . The increase was primarily due to the following:
• Subsequent to the completion of the Mergers, our results of operations include
depreciation expense primarily for the vessels acquired. We recognized
of incremental depreciation expense for the acquired vessels during the year
endedDecember 31, 2021 ;
• Amortization of the value recorded for favorable and unfavorable contracts
acquired in the Mergers of
• Increase in depreciation of
service in
• Increase in depreciation of
Interest expense
Interest expense increased by$88,601 for the year endedDecember 31, 2021 as compared to the year endedDecember 31, 2020 . The increase was primarily due to an increase in total principal outstanding due to the issuance of the 2025 Notes inSeptember 2020 , the 2026 Notes inApril 2021 , draws on the Revolving Facility, borrowings under the Vessel Term Loan Facility and the CHP Facility (all defined below); principal balance on outstanding facilities was$3,896,155 as ofDecember 31, 2021 as compared to total outstanding debt of$1,250,000 as ofDecember 31, 2020 . In conjunction with the Mergers, we assumed outstanding debentures issued by a subsidiary of Hygo and the outstanding debt of variable interest entities ("VIEs") that are now consolidated in our financial statements, totaling$630,563 as of the acquisition date. Although we have no control over the funding arrangements of these entities, we are the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the consolidated financial statements. Upon assumption of the debt held by VIEs, we recognized the liabilities assumed at fair value and amortization of the discount from carrying value has been recorded as additional interest expense. For the year endedDecember 31, 2021 , we recognized additional interest expense attributable to assumed debt of VIEs of$11,766 . Other (income) expense, net
Other (income) expense, net increased by
• Gains in investments in equity securities of
31, 2021;
• Changes in the fair value of the cross-currency interest rate swap and the
interest rate swaps acquired in connection with the Mergers, resulting additional income of$5,562 for the year endedDecember 31, 2021 .
Loss on extinguishment of debt, net
Loss on extinguishment of debt for the year endedDecember 31, 2021 was$10,975 . InNovember 2021 , we exercised our option to terminate the sale leaseback agreement of the Eskimo assumed in the Mergers in exchange for a total payment of$190,518 . The counterparty to this sale leaseback arrangement ("Eskimo SPV") has been consolidated in our financial statements subsequent to the Mergers. In connection with the termination of this financing arrangement, we recognized a loss on extinguishment of debt based on the difference between the repurchase price under the sale leaseback arrangement and the carrying value of the net assets of the Eskimo SPV upon deconsolidation. 63
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Loss on extinguishment of debt for the year endedDecember 31, 2020 was$33,062 as a result of the extinguishment of previous credit facilities inJanuary 2020 andSeptember 2020 . Tax provision We recognized a tax provision for the year endedDecember 31, 2021 of$12,461 compared to a tax provision of$4,817 for the year endedDecember 31, 2020 . The increase to the tax provision and effective tax rate for the year endedDecember 31, 2021 was primarily driven by an increase in pre-tax income in certain profitable foreign operations, primarily inJamaica . We also acquired profitable vessel operations in theUnited Kingdom in the Mergers. For the year endedDecember 31, 2021 , these increases in tax expense were partially offset by earnings generated in foreign jurisdictions with preferential tax rates.
Income from equity method investments
During the period after the completion of the Mergers, we recognized income from our investments in Hilli and CELSEPAR of$14,443 for the year endedDecember 31, 2021 . Our proportionate share of the earnings of$36,866 were offset by amortization of basis differences through our equity earnings of$22,423 for the year endedDecember 31, 2021 . During the period after the Mergers, our share of earnings from CELSEPAR was impacted by a foreign currency remeasurement gain of$2,261 for the year endedDecember 31, 2021 , primarily as a result of the remeasurement of the Nanook finance lease obligation.
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 include the results of operations of Hygo and
GMLP only since the completion of the Mergers in
the Mergers, we acquired a fleet of seven FSRUs, six LNG carriers and an
interest in a floating liquefaction vessel. We also acquired a 50% interest in
the Sergipe Facility and the Sergipe Power Plant, as well as the Barcarena
Facility and Barcarena Power Plant and the Santa Catarina Facility that are
currently in development. The results of operations of Hygo and GMLP began to
be included in our financial statements upon the closing of the acquisitions on
integration costs associated with these acquisitions, some of which would not
be expected in future periods. Our future results of operations may continue to
be impacted by costs to integrate the operations of Hygo and GMLP, including
costs to exit or modify transition service agreements or vessel management
agreements, all of which may be significant.
• Our historical financial results do not include significant projects that have
recently been completed or are near completion. Our results of operations for
the year ended
Facility, San Juan Facility, certain industrial end-users and our
Facility. We recently placed a portion of our La Paz Facility into service, and
in the fourth quarter of 2021, our revenue and results of operations began to
be impacted by operations in
Power Plant 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 the Suape Facility, Barcarena Facility, Santa Catarina Facility and Ireland Facility.
• Our historical financial results do not reflect new LNG supply agreements, as
well as our Fast LNG solution that will lower the cost of our LNG supply. We
currently purchase the majority of our supply of LNG from third parties,
sourcing approximately 96% of our LNG volumes from third parties for the year
ended
agreements for the purchase of approximately 601 TBtu of LNG at a price indexed
to
pricing in our previous long-term supply agreement. We have now secured supply
for LNG volumes equal to approximately 100% of our expected needs for our
Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility
and Puerto Sandino Facility for the next six years. 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. SinceAugust 2021 , LNG prices have increased materially. Due to this significant increase in market pricing of LNG, we have optimized our supply portfolio to sell a portion of our committed cargos in the market with delivery in the fourth quarter of 2021, and these cargo sales increased our revenues and results of operations. 64
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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 debt facilities and cash generated from operations. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund developments and transactions. We have historically funded our developments through proceeds from our IPO and debt and equity financing, most recently as follows:
• In
prior term loan facility in full.
• In
outstanding debt. No principal payments are due on the 2025 Notes until maturity in 2025.
• In
this issuance, these additional notes are included in the definition of 2025
Notes herein).
• In
received proceeds of
• In
• In
drew
• In
closed on the Vessel Term Loan Facility (defined below). Under this facility,
we borrowed an initial amount of
subject to satisfaction of certain conditions including the provision of security in relation to additional vessels. We have assumed total committed expenditures for all completed and existing projects to be approximately$1,913 million , with approximately$1,439 million having already been spent throughDecember 31, 2021 . This estimate represents the committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, the Suape Facility, the Barcarena Facility and the Santa Catarina Facility, as well committed expenditures to serve new industrial end-users. We expect to be able to fund all such committed projects with a combination of cash on hand, cash flows from operations and proceeds from theSouth Power 2029 Bonds (defined below). We may also enter into other financing arrangements to generate proceeds to fund our developments. ThroughDecember 31, 2021 , we have spent approximately$128 million to develop thePennsylvania Facility. Approximately$22 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$106 million , has been capitalized, and to date, we have repurposed approximately$17 million of engineering and equipment to our Fast LNG project.
Contractual Obligations
We are committed to make cash payments in the future pursuant to certain
contracts. The following table summarizes certain contractual obligations in
place as of
More than 5
(in thousands) Total Year 1 Years 2 to 3 Years 4 to 5 years
Long-term debt obligations $ 4,936,353 $ 305,575 $ 878,471 $ 3,341,677 $ 410,630
Purchase obligations 5,265,356 784,060 1,637,783 1,450,817 1,392,696
Lease obligations 420,329 67,131 101,295 68,393 183,510
Total $ 10,622,038 $ 1,156,766 $ 2,617,549 $ 4,860,887 $ 1,986,836
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Long-term debt obligations
For information on our long-term debt obligations, see "-Liquidity and Capital Resources-Long-Term Debt." The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as ofDecember 31, 2021 . Purchase obligations The Company is party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. For purchase commitments priced based upon an index such asHenry Hub , the amounts shown in the table above are based on the spot price of that index as ofDecember 31, 2021 . We have secured supply of LNG for approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility,La Paz Facility and Puerto Sandino Facility for the next six years. We have construction purchase commitments in connection with our development projects, including the La Paz Facility, Puerto Sandino Facility, Suape Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued. Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease. The Company currently has seven vessels under time charter leases with remaining non-cancellable terms ranging from one month to ten years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services. The Company has executed a lease for an LNG carrier that has not commenced as ofDecember 31, 2021 , which has a noncancelable terms of 7 years and includes fixed payments of approximately$198,100 ; these payments are not included in the table above. We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 20 to 25 years. The land site lease is held with an affiliate of the Company and has a remaining term of approximately five years with an automatic renewal term of five years for up to an additional 20 years. During 2020, we executed multiple lease agreements for the use of ISO tanks, and we began to receive these ISO tanks and the lease terms commenced during the second quarter of 2021. The lease term for each of these leases is five years and expected payments under these lease agreements have been included in the above table.
Office space includes space shared with affiliated companies in
Cash Flows
The following table summarizes the changes to our cash flows for the year ended
Year Ended December 31,
(in thousands) 2021 2020 Change
Cash flows from:
Operating activities $ 84,770 $ (125,566 ) $ 210,336
Investing activities (2,273,561 ) (157,631 ) (2,115,930 )
Financing activities 1,816,944 819,498 997,446
Net (decrease) increase in cash, cash equivalents, and restricted cash $ (371,847 ) $ 536,301 $ (908,148 )
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Cash provided by (used in) operating activities
Our cash flow provided by operating activities was$84,770 for the year endedDecember 31, 2021 , which increased by$210,336 from cash used in operating activities of$125,566 for the year endedDecember 31, 2020 . Our net income for the year endedDecember 31, 2021 , when adjusted for non-cash items, increased by$380,719 compared to the net loss, when adjusted for non-cash items, for the year endedDecember 31, 2020 . The increase to net income was offset by changes in working capital accounts, primarily increases in receivables, which was primarily comprised of a significant invoice of approximately$109,000 for a cargo sale that was settled shortly afterDecember 31, 2021 .
Cash used in investing activities
Our cash flow used in investing activities was$2,273,561 for the year endedDecember 31, 2021 , which increased by$2,115,930 from cash used in investing activities of$157,631 for the year endedDecember 31, 2020 . Cash used for the Mergers, net of cash acquired was$1,586,042 . Cash outflows for investing activities during the year endedDecember 31, 2021 were also used for continued development of the La Paz Facility, Puerto Sandino Facility, Suape Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution. During the year endedDecember 31, 2020 , we completed the CHP Plant and were in the final stages of development of the San Juan Facility, and we incurred lower cash outflows for investing activities for the year endedDecember 31, 2020 .
Cash provided by financing activities
Our cash flow provided by financing activities was$1,816,944 for the year endedDecember 31, 2021 , which increased by$997,446 from cash provided by financing activities of$819,498 for the year endedDecember 31, 2020 . Cash provided by financing activities during the year endedDecember 31, 2021 primarily consisted of proceeds received from the borrowings under the 2026 Notes of$1,500,000 , draw of$200,000 on the Revolving Facility, and borrowing of$430,000 under the Vessel Term Loan Facility. The proceeds received were further offset by repayments of debt, primarily the settlement of the sale-leaseback financing arrangement of the Eskimo for a total payment of$190,518 , financing fees paid in connection with the borrowings, tax payments for equity compensation made on behalf of employees and dividends paid for the year endedDecember 31, 2021 . Cash flow provided by financing activities during the year endedDecember 31, 2020 primarily consisted of proceeds received from the borrowings under the 2025 Notes of$1,000,000 and the borrowings under our previous credit agreement of$800,000 , partially offset by an original issue discount of$20,000 and financing fees. Additionally, the remaining proceeds from secured bonds issued inJamaica of$52,144 were received during the first quarter of 2020. A portion of these proceeds was used to fund the repayment of our previous credit agreement of$800,000 , the senior secured and unsecured bonds that had been issued inJamaica of$183,600 , and our previous term loan facility of$506,402 .
Long-Term Debt and Preferred Stock
2025 Notes
InSeptember 2020 , we issued$1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the "2025 Notes"). Interest is payable semi-annually in arrears onMarch 15 andSeptember 15 of each year, commencing onMarch 15, 2021 ; no principal payments are due until maturity onSeptember 15, 2025 . We may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.
The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.
We used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses.
In connection with the issuance of the 2025 Notes, we incurred$17,937 in origination, structuring and other fees. Issuance costs of$13,909 were deferred as a reduction of the principal balance of the 2025 Notes on the consolidated balance sheets; unamortized deferred financing costs related to lenders in the previously credit agreement that participated in the 2025 Notes were$6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes. As a portion of the repayment of the previous credit agreement was a modification, in the third quarter of 2020, we recorded$4,028 of third-party fees as an expense in the consolidated statements of operations and comprehensive loss. 67
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InDecember 2020 , we issued$250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). Proceeds received included a premium of$13,125 , which was offset by additional financing costs incurred of$4,566 . As ofDecember 31, 2021 andDecember 31, 2020 , remaining unamortized deferred financing costs for the 2025 Notes was$8,804 and$10,439 , respectively.
2026 Notes
InApril 2021 , we issued$1,500,000 of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the "2026 Notes") at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears onMarch 31 andSeptember 30 of each year, commencing onSeptember 30, 2021 ; no principal payments are due until maturity onSeptember 30, 2026 . We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as our existing first lien obligations under the 2025 Notes.
We used the net proceeds from this offering to fund the cash consideration for the Merger and pay related fees and expenses.
In connection with the issuance of the 2026 Notes, we incurred$25,217 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the consolidated balance sheets. As ofDecember 31, 2021 , total remaining unamortized deferred financing costs for the 2026 Notes was$22,488 . Vessel Term Loan Facility InSeptember 2021 ,Golar Partners Operating LLC , an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the "Vessel Term Loan Facility"). Under this facility, the Company borrowed an initial amount of$430,000 , which may be increased to$725,000 , subject to satisfaction of certain conditions including the provision of security in relation to additional vessels. Loans under the Vessel Term Loan Facility bear interest at a rate of LIBOR plus a margin of 3%. The Vessel Term Loan Facility shall be repaid in quarterly installments of$15,357 , with the final repayment date inSeptember 2024 . Quarterly principal payments will be increased to reflect any upsize of the Vessel Term Loan Facility to reflect a straight-line amortization profile over the remaining term. Obligations under the Vessel Term Loan Facility are guaranteed by GMLP and certain of GMLP's subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. The Company may prepay outstanding indebtedness without penalty, and certain events, such as (i) total loss; (ii) minimum security value; (iii) the sale or transfer of certain vessels; or (iv) the termination of the charter over the Hilli, will require a mandatory prepayment. The Vessel Term Loan Facility contains customary representations and warranties and customary affirmative and negative covenants, including financial covenants, chartering restrictions, restrictions on indebtedness, liens, investments, mergers, dispositions, prepayment of other indebtedness and dividends and other distributions. Financial covenants include requirements thatGMLP and Golar Partners Operating LLC maintain a certain amount of Free Liquid Assets, that the EBITDA to Consolidated Debt Service and the Net Debt to EBITDA ratios are no less than 1.15:1 and no greater than 6.50:1, respectively, and that ConsolidatedNet Worth is greater than$250,000 , each as defined in the Vessel Term Loan Facility. The Company was in compliance with these covenants as ofDecember 31, 2021 . 68
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In connection with the closing the Vessel Term Loan Facility, we incurred$6,324 in origination, structuring and other fees, which were deferred as a reduction of the principal balance of the Vessel Term Loan Facility on the consolidated balance sheets. As ofDecember 31, 2021 , total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was$5,652 .
Debenture Loan
As part of the Mergers, we assumed non-convertible Brazilian debentures issued by NFE Brasil, our indirect subsidiary, in the aggregate principal amount ofBRL 255,600 (approximately$45,000 ) dueSeptember 2024 , bearing interest at a rate equal to the one-day interbank deposit futures rate inBrazil plus 2.65% (the "Debenture Loan"). The Debenture Loan was recognized at fair value of$44,566 on the date of the Mergers, and the discount recognized in purchase accounting will result in additional interest expense until maturity. Interest and principal is payable on the Debenture Loan semi-annually onSeptember 13 andMarch 13 .
The Debenture Loan is fully and unconditionally guaranteed by 100% of the shares
issued by NFE Brasil owned by our consolidated subsidiary,
CHP Facility
InAugust 2021 ,NFE South Power Holdings Limited , a wholly owned subsidiary of NFE, entered into a financing agreement ("CHP Facility"). We received approximately$100,000 under the CHP Facility, and the CHP Facility is secured by a mortgage over the lease of the site on which the CHP Plant and related security. We incurred$3,243 in origination, structuring and other fees associated with entry into the CHP Facility, which was deferred as a reduction of the principal balance of the CHP Facility on the consolidated balance sheets. As ofDecember 31, 2021 , the remaining unamortized deferred financing costs for the CHP Facility was$3,180 . Subsequent toDecember 31, 2021 ,South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds ("South Power 2029 Bonds") and subsequently authorized the issuance of up to$285,000 inSouth Power 2029 Bonds.The South Power 2029 Bonds are secured by, amongst other things, the CHP Plant. Amounts outstanding at the time of the mutual rescission of the CHP Facility of$100,000 were credited towards the purchase price of theSouth Power 2029 Bonds. InFebruary 2022 ,$59,730 was funded under theSouth Power 2029 Bonds.The South Power 2029 Bonds will bear interest at an annual fixed rate of 6.50% and will mature seven years from the closing date of the final tranche. No principal payments will be due until 2025. It is expected that beginning inMay 2025 , principal payments will be due on a quarterly basis. Interest payments on outstanding principal balances will be due quarterly.South Power will continue to be required to comply with certain financial covenants as well as customary affirmative and negative covenants.The South Power 2029 Bonds also provides for customary events of default, prepayment and cure provisions. Revolving Facility InApril 2021 , we entered into a$200,000 senior secured revolving facility (the "Revolving Facility"). The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). Letters of credit issued under the$100,000 letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for us to extend the maturity date once in a one-year increment. Borrowings under the Revolving Facility bear interest at a per annum rate equal to LIBOR plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and LIBOR plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0.00% LIBOR floor. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium. The obligations under the Revolving Facility are guaranteed by each domestic and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially the same collateral as our existing first lien obligations under the 2025 Notes. The Revolving Facility contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. Financial covenants include requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters endingDecember 31, 2021 untilSeptember 30, 2023 and less than 4.0:1.0 for the fiscal quarter endedDecember 31, 2023 (each as defined in the Revolving Facility). The Company was in compliance with these covenants as ofDecember 31, 2021 . 69
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We incurred$4,321 in origination, structuring and other fees, associated with entry into the Revolving Facility. These costs have been capitalized within Other non-current assets on the consolidated balance sheets. As ofDecember 31, 2021 , total remaining unamortized deferred financing costs for the Revolving Facility was$3,807 . As ofDecember 31, 2021 , the full capacity of the Revolving Facility has been drawn and$200,000 remains outstanding.
Subsequent to
SPV Leasebacks and Loans
We assumed sale leaseback arrangements for four vessels as part of the Mergers.
The counterparty to each of the sale leaseback arrangements is a special purpose
vehicle ("SPV") wholly owned by financial institutions. The sale leasebacks
with SPVs were funded by loan facilities obtained by the SPV. Although we have
no control over the funding arrangements of these entities, we are the primary
beneficiary of the SPVs and consolidate the SPVs. Therefore, the effects of the
sale leaseback arrangements are eliminated upon consolidation of the SPVs and
only the outstanding loan facilities are presented as part of our consolidated
financial statements. The SPVs service the loan facilities through payments made
by us under the sale leaseback arrangements.
The SPV loans and the sale leaseback arrangements assumed in the Mergers contain
certain operating and financing restrictions and covenants that require: (a)
certain subsidiaries to maintain a minimum level of liquidity of $30,000 and
consolidated net worth of $123,950 , (b) certain subsidiaries to maintain a
minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not
exceed a maximum net debt to EBITDA ratio of 6.5:1, (d) certain subsidiaries to
maintain a minimum percentage of the vessel values over the relevant outstanding
loan facility balances of either 110% and 120%, (e) certain subsidiaries to
maintain a ratio of liabilities to total assets of less than 0.70:1. As of
December 31, 2021 , the Company was in compliance with all covenants under debt
and lease agreements.
Nanook Leaseback and Credit Facility
As part of the Mergers, we have assumed obligations under a sale and leaseback of the Nanook withCompass Shipping 23Corporation Limited (the "Nanook Leaseback"). Payments are due quarterly in 48 installments of$2,943 along with amounts owed for interest due based on LIBOR plus 3.5%, with a balloon payment of approximately$94,000 upon maturity.Compass Shipping 23Corporation Limited , the owner of the Nanook, has a long-term loan facility that is denominated in USD, which matures inSeptember 2030 and bears interest at a fixed rate of 2.5% (the "Nanook SPV Facility") and is repayable in a balloon payment on maturity. As of the acquisition date, the outstanding principal balance was$202,249 , and we recognized the fair value of this facility of$201,484 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity.
Penguin Leaseback and Credit Facility
As part of the Mergers, we have assumed obligations under a sale and leaseback of the Penguin with Oriental LNG 02 Limited (the "Penguin Leaseback"). Payments are due quarterly in 24 installments of$1,890 along with amounts owed for interest due based on LIBOR plus 3.6%, with a balloon payment of approximately$63,000 upon maturity. Oriental Fleet LNG 02 Limited, the owner of the Penguin, has a long-term loan facility that is denominated in USD, is repayable in quarterly installments with a balloon payment due upon maturity inDecember 2025 and bears interest at LIBOR plus a margin of 1.7%. The SPV also has amounts payable to its parent. As of the acquisition date, the outstanding principal balance was$104,882 , and we recognized the fair value of this facility and the amount due to the parent of$105,126 on the date of the Mergers. The premium recognized in purchase accounting will result in a reduction to interest expense until maturity.
Celsius Leaseback and Credit Facility
As part of the Mergers, we have assumed obligations under a sale and leaseback of the Celsius withNoble Celsius Shipping Limited (the "Celsius Leaseback"). Payments are due quarterly in 28 installments of$2,679 in addition to amounts owed for interest based on LIBOR plus 3.9%, with a balloon payment of approximately$45,000 upon maturity. 70
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Noble Celsius Shipping Limited , the owner of the Celsius, has a long-term loan facility that is denominated in USD,$76,179 of which is repayable in quarterly installments over a term of approximately seven years with a balloon payment of$37,179 due upon maturity inMay 2027 and bears interest at LIBOR plus a margin of 1.8%. The SPV has another facility with its parent for the remaining principal of$45,200 , which is due as a balloon payment upon maturity inMarch 2023 and bears interest at a fixed rate of 4.0%. As of the acquisition date, the total outstanding principal balance was$121,379 , and we recognized the fair value of these facilities of$121,308 on the date of the Mergers. The discount recognized in purchase accounting will result in additional interest expense until maturity.
Eskimo Leaseback and Credit Facility
As part of the Mergers, we assumed obligations under a sale and leaseback of the Eskimo with Sea 23Leasing Co. Limited ofChina Merchants Bank Leasing (the "Eskimo Leaseback"). Sea 23Leasing Co. Limited ("Eskimo SPV"), the owner of the Eskimo, had a long-term loan facility that is denominated in USD, had a loan term of ten years and bore interest at a rate of LIBOR plus a margin of 2.66% (the "Eskimo SPV Facility"). As of the acquisition date of GMLP, the outstanding principal balance was$160,520 , and we recognized the fair value of this facility of$158,072 . The discount recognized in purchase accounting was recognized as additional interest expense until the deconsolidation of the Eskimo SPV. InNovember 2021 , we exercised our option to repurchase the Eskimo for a total payment of$190,518 . After exercising the repurchase option, we no longer have a controlling financial interest in the Eskimo SPV and no longer recognize the Eskimo SPV Facility in our consolidated financial statements. In connection with the repurchase of the Eskimo, we recognized a loss on extinguishment of debt of$10,975 for the year endedDecember 31, 2021 .
Series A Preferred Units
The 8.75% Series A Cumulative Redeemable Preferred Units issued by GMLP (the "Series A Preferred Units") remained outstanding following the GMLP Merger and were recognized as non-controlling interest on the consolidated balance sheets. Distributions on the Series A 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 Series A 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 afterOctober 31, 2022 , the Series A Preferred Units may be redeemed, in whole or in part, at a redemption price of$25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon on the date of redemption, whether declared or not.
Debt obligations of equity method investees
We account for the investments inCELSEPAR and Hilli LLC acquired in the Mergers under the equity method of accounting. The debt obligations of these entities are not reported separately in our consolidated financial statements, and the following discussion summarizes the key terms of each entity's obligations.
Sergipe Debt Financing
To finance construction of the Sergipe Facility and the Sergipe Power Plant, CELSE signed financing agreements with amounts made available by banks and multilateral organizations throughout 2018 (the "CELSE Facility"). As ofDecember 31, 2021 , amounts outstanding and the effective interest rates under the CELSE Facility were as set forth below. Principal and interest payments are due each October and April. The CELSE Facility matures inApril 2032 . Effective Interest Credit facility (Real and USD in millions) Principal Outstanding Rate (1) IFCR$ 899.4 ($160.3 ) IPCA + 9.69% Inter-American Development BankR$ 744.1 ($132.6 ) IPCA + 9.79% IDB Invest $ 35.7 3M LIBOR + 5.4% IDC China Fund $ 46.9 3M LIBOR + 5.4%
(1)
CELSE also issued debentures in the aggregate principal amount ofR$3,370.0 million (net proceeds of$897.2 million as of the issuance date), dueApril 2032 , bearing interest at a fixed rate of 9.85% (the "CELSE Debentures"). As ofDecember 31, 2021 , the principal balance of the CELSE Debentures wasR$3,113 million ($554.7 million as ofDecember 31, 2021 ). Interest is payable on the CELSE Debentures semi-annually on eachApril 15 andOctober 15 , beginning onOctober 15, 2018 . The CELSE Debentures are amortized and repaid in 24 consecutive semi-annual installments on each ofApril 15 andOctober 15 , that commenced onOctober 15, 2020 . 71
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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 afterMarch 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. InJuly 2021 , CELSE successfully completed a consent solicitation to amend certain provisions of the financing documents to permit CELSE to incur certain debt related to the working capital facility described below and to release certain existing security over the variable revenues to be received by CELSE under its power purchase agreements. CELSEPAR has entered into a Standby Guarantee and Credit Facility Agreement withGE Capital EFS Financing, Inc. ("GE Capital "), as lender, and Ebrasil Energia Ltda. ("Ebrasil") and us, each as sponsor (the "GE Credit Facility"). Pursuant to the GE Credit Facility,GE Capital agreed to provide$120,000 to CELSEPAR in connection with its 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 onMay 30 andNovember 30 each year, beginning onMay 30, 2020 . All interest due to date has been capitalized into the principal balance, and there have been no principal payments paid to date. The GE Credit Facility matures onNovember 30, 2024 .
The
GE Credit Facility includes covenants and events of default that are customary for similar transactions.
InJuly 2021 , CELSE and CELSEPAR entered into a working capital facility for the posting of certain letters of credit in favor of the supplier of LNG and the financing of LNG costs to satisfy dispatch requirements prior to receiving related variable revenues. The working capital facility is in an aggregate amount of up to$200.0 million (or its equivalent in Reais). The facility has a term of 12 months, renewable for equal periods by mutual agreement of the parties. Amounts disbursed under the working capital facility accrue interest at a rate of (i) DI Rate + 3.50% per year in respect of a bank credit bill, (ii) 2.50% per year for standby letters of credit, (iii) DI Rate + 3.50% per year in respect of any import financing (FINIMP) modality, and (iv) DI Rate + 3.50% per year for any bank loan. The DI Rate is made by reference to Libor+, according to the pricing at the time of request. As ofDecember 31, 2021 , standby letters of credit issued under this facility for the benefit of CELSE pursuant to the working capital facility totaled$106 million . Standby letters of credit are guaranteed, jointly but not severally, by CELSE's shareholders, NFE and Electricidade doBrasil S.A. -Ebrasil.
Golar Hilli Leaseback
As part of the Mergers, we acquired an investment inHilli LLC ;Golar Hilli Corporation ("Hilli Corp "), is a direct subsidiary ofHilli LLC and is a party to a Memorandum of Agreement withFortune Lianjiang Shipping S.A. , a subsidiary ofChina State Shipbuilding Corporation ("Fortune"), pursuant to whichHilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the "Hilli Leaseback"). Under the Hilli Facility,Hilli Corp pays Fortune equal quarterly principal payments plus interest based on LIBOR plus a margin of 4.15%. Our 50% share ofHilli Corp's indebtedness of$729 million amounted to$364.5 million as ofDecember 31, 2021 . As part of the Mergers, we have assumed a guarantee of 50% of the outstanding principal and interest amounts payable byHilli Corp under the Hilli Leaseback. We also assumed a guarantee of the letter of credit ("LOC Guarantee") issued by a financial institution in the event ofHilli Corp's underperformance or non-performance under its tolling agreement. Certain of our subsidiaries are 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; and (iii) a consolidated tangible net worth of$123,950 .
Letter of Credit Facility
InJuly 2021 , the Company entered into an uncommitted letter of credit and reimbursement agreement with a bank for the issuance of letters of credit for an aggregate amount of up to$75,000 . Outstanding letters of credit are subject to a fee of 1.75% to be paid quarterly, and interest is payable on the principal amounts of unreimbursed letter of credit draws under the facility at a rate of the higher of the bank's prime rate or the Federal Funds Effective Rate plus 0.50% and a margin of 1.75%. We are using this uncommitted letter of credit and reimbursement agreement to reduce the cash collateral required under existing letters of credit releasing restricted cash. A portion of our restricted cash balance supports existing letters of credit, and this uncommitted letter of credit and reimbursement agreement has replaced these letters of credit and released restricted cash, enhancing our ability to manage the working capital needs of the business. 72
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Summary of Critical Accounting Estimates
The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management evaluates its estimates and related assumptions regularly and will continue to do so as we further grow our business. We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management's judgments and estimates.
Revenue recognition
Terminals and infrastructure
Within the Terminals and Infrastructure segment, our contracts with customers
may contain one or several performance obligations usually consisting of the
sale of LNG, natural gas, power and steam, which are outputs from our natural
gas-fueled infrastructure and the sale of LNG cargos. The transaction price for
each of these contracts is structured using similar inputs and factors
regardless of the output delivered to the customer. The customers consume the
benefit of the natural gas, power and steam when they are delivered to the
customer's power generation facilities or interconnection facility. Natural gas,
power and steam qualify as a series with revenue being recognized over time
using an output method, based on the quantity of natural gas, power or steam
that the customer has consumed. LNG is typically delivered in containers
transported by truck to customer sites but may also be delivered via vessel to
an unloading point specified in a contract. Revenue from sales of LNG delivered
by truck is recognized at the point in time at which physical possession and the
risks and rewards of ownership transfer to the customer, either when the
containers are shipped or delivered to the customers' storage facilities,
depending on the terms of the contract. Because the nature, timing and
uncertainty of revenue and cash flows are substantially the same for LNG,
natural gas, power and steam, we have presented Operating revenue on an
aggregated basis.
We have concluded that variable consideration included in its agreements meets
the exception for allocating variable consideration. As such, the variable
consideration for these contracts is allocated to each distinct unit of LNG,
natural gas, power or steam delivered and recognized when that distinct unit is
delivered to the customer.
Our contracts with customers to supply natural gas or LNG may contain a lease of
equipment, which may be accounted for as a finance or operating lease. For
operating leases, we have concluded that the predominant component of the
transaction is the sale of natural gas or LNG and therefore have elected not to
separate the lease component. The lease component of such operating leases is
recognized as Operating revenue in the consolidated statements of operations and
comprehensive income (loss). We allocate consideration in agreements containing
finance leases between lease and non-lease components based on the relative fair
value of each component. The fair value of the lease component is estimated
based on the estimated standalone selling price of the same or similar equipment
leased to the customer. We estimate the fair value of the non-lease component by
forecasting volumes and pricing of gas to be delivered to the customer over the
lease term.
The current and non-current portion of finance leases are recorded within
Prepaid expenses and other current assets and Finance leases, net on the
consolidated balance sheets, respectively. For finance leases accounted for as
sales-type leases, the profit from the sale of equipment is recognized upon
lease commencement in Other revenue in the consolidated statements of operations
and comprehensive income (loss). The lease payments for finance leases are
segregated into principal and interest components similar to a loan. Interest
income is recognized on an effective interest method over the lease term and
included in Other revenue in the consolidated statements of operations and
comprehensive income (loss). The principal component of the lease payment is
reflected as a reduction to the net investment in the lease.
In addition to the revenue recognized from the finance lease components of
agreements with customers, Other revenue includes revenue recognized from the
construction, installation and commissioning of equipment, inclusive of natural
gas delivered for the commissioning process, to transform customers' facilities
to operate utilizing natural gas or to allow customers to receive power or other
outputs from our natural gas-fueled power generation facilities and the sale of
LNG cargos. Revenue from these development services is recognized over time as
we transfer control of the asset to the customer or based on the quantity of
natural gas consumed as part of commissioning the customer's facilities until
such time that the customer has declared such conversion services have been
completed. If the customer is not able to obtain control over the asset under
construction until such services are completed, revenue is recognized when the
services are completed and the customer has control of the infrastructure. Such
agreements may also include a significant financing component, and we recognize
revenue for the interest income component over the term of the financing as
Other revenue.
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The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the consolidated balance sheets.
Shipping and handling costs are not considered to be separate performance obligations. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas.
We collect sales taxes from our customers based on sales of taxable products and remits such collections to the appropriate taxing authority. We have elected to present sales tax collections in the consolidated statements of operations and comprehensive income (loss) on a net basis and, accordingly, such taxes are excluded from reported revenues. We elected the practical expedient under which we do not adjust consideration for the effects of a significant financing component for those contracts where we expect at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less.
Ships
Charter contracts for the use of the FSRUs and LNG carriers acquired as part of
the Mergers are leases as the contracts convey the right to obtain substantially
all of the economic benefits from the use of the asset and allow the customer to
direct the use of that asset.
At inception, we make an assessment on whether the charter contract is an
operating lease or a finance lease. In making the classification assessment, we
estimate the residual value of the underlying asset at the end of the lease term
with reference to broker valuations. None of the vessel lease contracts contain
residual value guarantees. Renewal periods and termination options are included
in the lease term if we believe such options are reasonably certain to be
exercised by the lessee. Generally, lease accounting commences when the asset is
made available to the customer, however, where the contract contains specific
customer acceptance testing conditions, the lease will not commence until the
asset has successfully passed the acceptance test. We assess leases for
modifications when there is a change to the terms and conditions of the contract
that results in a change in the scope or the consideration of the lease.
For charter contracts that are determined to be finance leases accounted for as
sales-type leases, the profit from the sale of the vessel is recognized upon
lease commencement in Other revenue in the consolidated statements of operations
and comprehensive income (loss). The lease payments for finance leases are
segregated into principal and interest components similar to a loan. Interest
income is recognized on an effective interest method over the lease term and
included in Other revenue in the consolidated statements of operations and
comprehensive income (loss). The principal component of the lease payment is
reflected as a reduction to the net investment in the lease. Revenue related to
operating and service agreements in connection with charter contracts accounted
for as sales-type leases are recognized over the term of the charter as the
service is provided within Vessel charter revenue in the consolidated statements
of operations and comprehensive income (loss).
Revenues include fixed minimum lease payments under charters accounted for as
operating leases and fees for repositioning vessels. Revenues generated from
charters contracts are recorded over the term of the charter on a straight-line
basis as service is provided and is included in Vessel charter revenue in the
consolidated statements of operations and comprehensive loss. Fixed revenue
includes fixed payments (including in-substance fixed payments that are
unavoidable) and variable payments based on a rate or index. For operating
leases, we have elected the practical expedient to combine service revenue and
operating lease income as the timing and pattern of transfer of the components
are the same. Variable lease payments are recognized in the period in which the
circumstances on which the variable lease payments are based occur.
Repositioning fees are included in Vessel charter revenues and are recognized at
the end of the charter when the fee becomes fixed and determinable. However,
where there is a fixed amount specified in the charter, which is not dependent
upon redelivery location, the fee will be recognized evenly over the term of the
charter.
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Costs directly associated with the execution of the lease or costs incurred after lease inception but prior to the commencement of the lease that directly relate to preparing the asset for the contract are capitalized and amortized in Vessel operating expenses in the consolidated statements of operations and comprehensive income (loss) over the lease term. Our LNG carriers may participate in a LNG carrier pool collaborative arrangement with Golar LNG Limited, referred to as theCool Pool .The Cool Pool allows the pool participants to optimize the operation of the pool vessels through improved scheduling ability, cost efficiencies and common marketing. Under the Pool Agreement, the Pool Manager is responsible, as agent, for the marketing and chartering of the participating vessels and paying certain voyage costs such as port call expenses and brokers' commissions in relation to employment contracts, with each of the pool participants continuing to be fully responsible for fulfilling the performance obligations in the contract. We are primarily responsible for fulfilling the performance obligations in the time charters of vessels owned by the Company, and we are the principal in such time charters. Revenue and expenses for charters of our vessels that participate in theCool Pool are presented on a gross basis within Vessel charter revenues and Vessel operating expenses, respectively, in the consolidated statements of operations and comprehensive loss. Our allocation of our share of the net revenues earned from the other pool participants' vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses in the consolidated statements of operations and comprehensive loss.
Impairment of long-lived assets
We perform a recoverability assessment of long-lived assets whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Indicators may include, but are not limited to, adverse changes
in the regulatory environment in a jurisdiction where we operate, unfavorable
events impacting the supply chain for LNG to our operations, a decision to
discontinue the development of a long-lived asset, early termination of a
significant customer contract, or the introduction of newer technology. We
exercise judgment in determining if any of these events represent an impairment
indicator requiring a recoverability assessment.
Our business model requires investments in infrastructure often concurrently
with our customer's investments in power generation or other assets to utilize
LNG. Our costs to transport and store LNG are based upon our customer's
contractual commitments once their assets are fully operational. We expect
revenue under these contracts to exceed construction and operational costs,
based on the expected term and revenue of these contracts. Additionally, our
infrastructure assets are strategically located to provide critical inputs to
our committed customer's operations and our locations allow us to expand to
additional opportunities within existing markets. These projects are subject to
risks related to successful completion, including those related to government
approvals, site identification, financing, construction permitting and contract
compliance.
Our long-term, take-or pay contracts to deliver natural gas or LNG to our
customers also limit our exposure to fluctuations in natural gas and LNG as our
pricing is largely based on the Henry Hub index plus a contractual spread. Based
on the long-term nature of our contracts and the market value of the underlying
assets, changes in the price of LNG do not indicate that a recoverability
assessment of our assets is necessary. Further, we plan to utilize our own
liquefaction facilities to manufacture our own LNG at attractive prices, secure
LNG to supply our expanding operations and reduce our exposure to future LNG
price variations in the long term.
We have also considered the impacts of the ongoing COVID-19 pandemic, including
the restrictions that governments may put in place and the resulting direct and
indirect economic impacts on our current operations and expected development
budgets and timelines. We primarily operate under long-term contracts with
customers, including long-term charter contracts acquired in the Mergers and
many of which contain fixed minimum volumes that must be purchased on a
"take-or-pay" basis, even in cases when our customer's consumption has
decreased. We have not changed our payment terms with customers, and there has
not been any deterioration in the timing or volume of collections.
Based on the essential nature of the services we provide to support power
generation facilities, our operations and development projects have not been
significantly impacted by responses to the COVID-19 pandemic to date. We will
continue to monitor this uncertain situation and local responses in
jurisdictions where we do business to determine if there are any indicators that
a recoverability assessment for our assets should be performed.
The COVID-19 pandemic has also significantly impacted energy markets, and the
price of oil traded at historic low prices in 2020. Future expansion of our
business is dependent upon LNG being a competitive source of energy and
available at a lower cost than the cost to deliver other alternative energy
sources, such as diesel or other distillate fuels. Although LNG is currently
trading at historical high prices, we believe that over the long-term LNG and
natural gas will remain a competitive fuel source for customers.
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We have considered that the market price of LNG can vary widely, including decreases throughout 2019 and 2020 and dramatic increases in the second half of 2021. Our extensive and growing portfolio of downstream terminals and infrastructure, together with our locked-in gas supply, provides powerful flexibility to serve customer needs and participate in the opportunities created by market disruptions. Due to the decline in LNG prices in 2019 and 2020, we executed four long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower our supply contract executed in 2018. Further, we took advantage of the lower market pricing of LNG to supply our operations for the second half of 2020. We also executed an additional addendum to one of our supply agreements in 2021 to continue to secure 100% of our LNG supply needs for our Montego Bay Facility, Old Harbour Facility,San Juan Facility, La Paz Facility and Puerto Sandino Facility through 2030. LNG prices are currently experiencing dramatic increases. We have used optimized our supply portfolio to sell a portion of our committed cargos in the market with delivery in fourth quarter of 2021, and these cargo sales have increased our revenues and results of operations. When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.
Share-based compensation
We estimate the fair value of RSUs and performance stock units ("PSUs") granted
to employees and non-employees on the grant date based on the closing price of
the underlying shares on the grant date and other fair value adjustments to
account for a post-vesting holding period. These fair value adjustments were
estimated based on the Finnerty model.
For our PSUs, we reassess the probability of the achievement of the performance
metric each reporting period to estimate the amount of shares that will vest.
Any increase or decrease in share-based compensation expense resulting from an
adjustment in the estimated vesting is treated as a cumulative catch-up in the
period of adjustment. Our estimate of whether the performance metric will be met
is impacted by the timing of our development projects becoming operational and
our ability to achieve the expected results of operations, execution of
definitive agreements for new projects, costs of LNG and our ability to execute
sale of LNG cargos at favorable pricing and facilitate delivery of these cargos
during periods of significant volatility in LNG prices. If any of the
assumptions or estimates used change significantly, share-based compensation
expense may differ materially from what we have recorded in the current period.
Business combinations and goodwill
We evaluate each purchase transaction to determine whether the acquired assets
meet the definition of a business. If substantially all of the fair value of
gross assets acquired is concentrated in a single identifiable asset or group of
similar identifiable assets, then the set of transferred assets and activities
is not a business. If not, for an acquisition to be considered a business, it
would have to include an input and a substantive process that together
significantly contribute to the ability to create outputs. A substantive process
is not ancillary or minor, cannot be replaced without significant costs, effort
or delay or is otherwise considered unique or scarce. To qualify as a business
without outputs, the acquired assets would require an organized workforce with
the necessary skills, knowledge and experience that performs a substantive
process.
For acquisitions that are not deemed to be businesses, the assets acquired are
recognized based on their cost to us as the acquirer, and no gain or loss is
recognized. The cost of assets acquired in a group is allocated to individual
assets within the group based on their relative fair values and no goodwill is
recognized. Transaction costs related to acquisition of assets are included in
the cost basis of the assets acquired.
We account for acquisitions that qualify as business combinations by applying
the acquisition method. Transaction costs related to the acquisition of a
business are expensed as incurred and excluded from the fair value of
consideration transferred. Under the acquisition method of accounting, the
identifiable assets acquired, liabilities assumed and noncontrolling interests
in an acquired entity are recognized and measured at their estimated fair
values. The excess of the fair value of consideration transferred over the fair
values of identifiable assets acquired, liabilities assumed and noncontrolling
interests in an acquired entity, net of fair value of any previously held
interest in the acquired entity, is recorded as goodwill.
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The Company performs valuations of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity and allocates the purchase price to its respective assets, liabilities and noncontrolling interests. Determining the fair value of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity requires management to use significant judgment and estimates, including the selection of appropriate valuation methodologies, vessel market day rates, and discount rates. The Company estimated the fair value of the vessels acquired in the Mergers using a combination of the income approach and the cost approach, which determines the replacement costs for the vessel assets, adjusting for age and condition. Management's estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. As a result, actual results may differ from these estimates. During the measurement period, the Company may record adjustments to acquired assets, liabilities assumed and noncontrolling interests, with corresponding offsets to goodwill. Upon the conclusion of a measurement period, any subsequent adjustments are recorded to earnings. We use estimates, assumptions and judgments when assessing the recoverability of goodwill. We test for impairment on an annual basis, or more frequently if a significant event of circumstance indicates the carrying amounts may not be recoverable. The assessment of goodwill for impairment may initially be performed based on qualitative factors to determine if it is more likely than not that the fair value of the reporting unit to which the goodwill is assigned is less than the carrying value. If so, a quantitative assessment is performed to determine if an impairment has occurred and to measure the impairment loss. We completed our annual goodwill impairment evaluation using a qualitative analysis assessment during the fourth quarter of 2021. Under the qualitative assessment, we consider several qualitative factors, including macroeconomic conditions (including changes in interest rates and foreign currency exchange rates), industry and market considerations (including demand for cleaner energy sources and the market price for LNG), the recent and projected financial performance of the reporting unit, as well as other factors.
There was no indication of impairments of goodwill for the year ended
Recent Accounting Standards
For descriptions of recently issued accounting standards, refer to "Note 3. Adoption of new and revised standards" of our notes to consolidated financial statements included elsewhere in this Annual Report.
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