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New Fortress Energy Inc. - Annual Report: 2021 (Form 10-K)


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the year ended December 31, 2021
OR
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                to_______
Commission File Number:001-38790
New Fortress Energy Inc.
(Exact Name of Registrant as Specified in its Charter)

Delaware
 
83-1482060
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)

111 W. 19th Street, 8th Floor
New York, NY
 
10011
(Address of principal executive offices)
 
(Zip Code)
 
Registrant’s telephone number, including area code: (516) 268-7400
Securities registered pursuant to Section 12(b) of the Act:

Title of each class
Trading Symbol(s)
Name of each exchange on which registered
on which registered
Class A common stock
NFE
 NASDAQ Global Select Market
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ☒ No ☐
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes   No 
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   No
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes  No  
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  
Accelerated filer  
Non-accelerated filer
Smaller reporting company  
 
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes   No
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed as of June 30, 2021 (the last business day of the registrant’s most recently completed second fiscal quarter), based on the closing price of the Class A shares on the Nasdaq Global Select Market, was $2,754.1 million.
 
At February 24, 2022, the registrant had 206,863,242 shares of Class A common stock outstanding.
 
Documents Incorporated by Reference:
 
Portions of the registrant’s definitive proxy statement for the registrant’s 2022 annual meeting, to be filed within 120 days after the close of the registrant’s fiscal year, are incorporated by reference into Parts II and III of this Annual Report on Form 10-K.
 




Table of Contents

1
2
3
 
Items 1 and 2.
3
 
Item 1A.
17
 
Item 1B.
50
 
Item 3.
50
 
Item 4.
50
51
 
Item 5.
51
 
Item 6.
52
 
Item 7.
53
 
Item 7A.
77
 
Item 8.
78
 
Item 9.
78
 
Item 9A.
78
 
Item 9B.
79
 
Item 9C.
79
80
 
Item 10.
80
 
Item 11.
80
 
Item 12.
80
 
Item 13.
80
 
Item 14.
80
81
 
Item 15.
81
 
Item 16.
85
86

GLOSSARY OF TERMS

As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this Annual Report on Form 10-K (“Annual Report”), the terms listed below have the following meanings:

ADO
automotive diesel oil
   
Bcf/yr
billion cubic feet per year
   
Btu
the amount of heat required to raise the temperature of one avoirdupois pound of pure water from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an absolute
pressure of 14.696 pounds per square inch gage
   
CAA
Clean Air Act
   
CERCLA
Comprehensive Environmental Response, Compensation and Liability Act
   
CWA
Clean Water Act
   
DOE
U.S. Department of Energy
   
DOT
U.S. Department of Transportation
   
EPA
U.S. Environmental Protection Agency
   
FTA countries
countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
   
GAAP
generally accepted accounting principles in the United States
   
GHG
greenhouse gases
   
GSA
gas sales agreement
   
Henry Hub
a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange
   
ISO container
International Organization of Standardization, an intermodal container
   
LNG
natural gas in its liquid state at or below its boiling point at or near atmospheric pressure
   
MMBtu
one million Btus, which corresponds to approximately 12.1 LNG gallons
   
mtpa
metric tons per year
   
MW
megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt.
   
NGA
Natural Gas Act of 1938, as amended
   
non-FTA countries
countries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted
   
OPA
Oil Pollution Act
   
OUR
Office of Utilities Regulation (Jamaica)
   
PHMSA
Pipeline and Hazardous Materials Safety Administration
   
PPA
power purchase agreement
   
SSA
steam supply agreement
   
TBtu
one trillion Btus, which corresponds to approximately 12,100,000 LNG gallons

CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K for the year ended December 31, 2021 (this “Annual Report”) contains forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this Annual Report other than historical information are forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance or our projected business results. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “projects,” “targets,” “potential” or “continue” or the negative of these terms or other comparable terminology. Such forward-looking statements are necessarily 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. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:

our limited operating history;

the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest and their ability to make dividends or distributions to us;

construction and operational risks related to our facilities and assets, including cost overruns and delays;

complex regulatory and legal environments related to our business, assets and operations, including actions by governmental entities or changes to regulation or legislation, in particular related to our permits, approvals and authorizations for the construction and operation of our facilities;

delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;

failure to maintain sufficient working capital for the development and operation of our business and assets;

failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;

failure to convert our customer pipeline into actual sales;

lack of asset, geographic or customer diversification, including loss of one or more of our customers;

competition from third parties in our business;

failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;

cyclical or other changes in the demand for and price of LNG and natural gas;

inability to procure LNG at necessary quantities or at favorable prices to meet customer demand, or otherwise to manage LNG supply and price risks, including hedging arrangements;

inability to successfully develop and implement our technological solutions;

inability to service our debt and comply with our covenant restrictions;

inability to obtain additional financing to effect our strategy;

inability to successfully complete mergers, sales, divestments or similar transactions related to our businesses or assets or to integrate such businesses or assets and realize the anticipated benefits, including with respect to the Mergers;

economic, political, social and other risks related to the jurisdictions in which we do, or seek to do, business;

weather events or other natural or manmade disasters or phenomena;

the extent of the global COVID-19 pandemic or any other major health and safety incident;

increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;

the tax treatment of, or changes in tax laws applicable to, us or our business or of an investment in our Class A shares; and

other risks described in the “Risk Factors” section of this Annual Report.

When considering forward-looking statements, you should keep in mind the risks set forth under “Item 1A. Risk Factors” and other cautionary statements included in this Annual Report. The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We undertake no duty to update these forward-looking statements, even though our situation may change in the future. Furthermore, we cannot guarantee future results, events, levels of activity, performance, projections or achievements.

PART I

Items 1 and 2.
Business and Properties

Unless the context otherwise requires, references in this Annual Report to the “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries. When used in a historical context, “our,” “us,” “we” 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. When used in a historical context that is prior to the completion of NFE’s initial public offering (“IPO”), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Holdings LLC, a Delaware limited liability company (“New Fortress Energy Holdings”), our predecessor for financial reporting purposes. When used in a historical context, prior to completion of Mergers (as defined herein), “Company,” “we,” “our,” “us” or like terms refer to 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 after completion of the Mergers, “Company,” “we,” “our,” “us” or like terms refer to 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 making positive and meaningful impacts on communities and the environment. 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 below under “Sustainability—Toward a Carbon-Free Future.”

We deliver targeted energy solutions by employing an integrated LNG supply and delivery model:

LNG and Natural Gas Supply and Liquefaction – We supply LNG and natural gas to our power plants for operations and to our customers.  We typically supply LNG and natural gas to our customers by entering into long-term supply contracts, which are generally based on an index such as Henry Hub plus a fixed fee component. The contracts are a mixture of delivered and free on board (loaded) cargoes. In addition, we supply LNG and natural gas to our customers from open market purchases and LNG from our existing liquefaction and storage facility in Miami, Florida (the “Miami Facility”) and our own portfolio of long-term contracted supply agreement with third-party suppliers.

Shipping – We have a fleet of 20 vessels, some of which we operate and some of which are chartered in from third parties. We operate seven regasification units (“FSRUs”) and eleven liquefied natural gas carriers (“LNGCs”), and including floating storage units (“FSUs”), and we have an interest in a floating liquefaction vessel, the Hilli Episeyo (the “Hilli”), which we use for our operations. Certain of these vessels are currently under third-party charter agreements. As these third-party charters expire, we plan to employ the vessels internally to support the Company’s existing facilities and international project pipeline. We also engage long-term charters for the transport LNG from ports to our downstream facilities and gasify LNG for ultimate delivery to our customers.

Facilities – Through our network of current and planned downstream facilities and logistics assets, we are strategically positioned to deliver gas and power solutions to our customers seeking either to transition from environmentally dirtier distillate fuels such as automotive diesel oil (“ADO”) and heavy fuel oil (“HFO”) or to purchase natural gas to meet their current fuel needs.

We analyze and seek to implement innovative and new technologies that complement our businesses to reduce our costs, achieve efficiencies for our business and our customers and advance our long-term goals, such as our ISO container distribution system, our Fast LNG solution and our hydrogen project.

Our Business Model

As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to shipping, logistics, facilities and conversion or development of natural gas-fired power generation. Historically, natural gas procurement or liquefaction, transportation, regasification and power generation projects have been developed separately and have required multilateral or traditional financing sources, which has inhibited the development of natural gas-fired power in many developing countries. In executing our business model, we have the capability to build or arrange any necessary infrastructure ourselves without reliance on multilateral financing sources or traditional project finance structures, so that we maintain our strategic flexibility and optimize our portfolio.

We currently conduct our operations at the following facilities:


our LNG storage and regasification facility at the Port of Montego Bay, Jamaica (the “Montego Bay Facility”),

our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility” and, together with the Montego Bay Facility, the “Jamaica Facilities”),

our landed micro-fuel handling facility in San Juan, Puerto Rico (the “San Juan Facility”),

our marine LNG storage and regasification facility in Sergipe, Brazil (the “Sergipe Facility”),

our LNG receiving facility in La Paz, Mexico (the “La Paz” Facility”), and

at our Miami Facility.

In addition, we are currently developing facilities in Brazil, Nicaragua, Ireland and other locations, as described below in more detail. We are in active discussions with additional customers to develop projects in multiple regions around the world who 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.

Our Facilities

We look to build facilities in locations where the need for LNG is significant. We design and construct LNG and power facilities to meet the supply and demand specifications of our current and potential future customers in the applicable region. In these markets, we first seek to identify and establish “beachhead” target markets for the sale of LNG, natural gas or natural gas-fired power. We then seek to convert and supply natural gas to additional power customers. Finally, our goal is to expand within the market by supplying additional industrial and transportation customers.

Our facilities position us to acquire and supply LNG to customers and natural gas-fired power in a number of attractive markets around the world. Downstream, we have eleven facilities that are either operational or under active development.  We currently have five operational LNG terminal facilities and six under active development, as well as four operational power plant facilities and seven under active development, as described below. Our LNG facilities currently operating or under development are expected to be capable of receiving between 100,000 and 9.6 million gallons of LNG (8,000 and 800,000 MMBtu) per day depending upon the needs of our customers and potential demand in the region.

Set forth below is additional detail regarding each of our LNG and power facilities:

Montego Bay, Jamaica – Our Montego Bay Facility commenced commercial operations in October 2016. The Montego Bay Facility 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. It supplies natural gas to the 145MW power plant (the “Bogue Power Plant”) operated by Jamaica Public Service Company Limited (“JPS”) pursuant to a long-term contract for natural gas equivalent to approximately 310,000 gallons of LNG (25,600 MMBtu) per day. The Montego Bay Facility also supplies numerous on-island industrial users with natural gas or LNG pursuant to numerous offtake contracts of various durations, some of which contain take-or-pay provisions. We have total aggregate contracted volumes of approximately 415,000 gallons of LNG (35,000 MMBtu) per day at our Montego Bay Facility with a weighted average remaining contract length of 18 years as of December 31, 2021. We have the ability to service other potential customers with the excess capacity of the Montego Bay Facility, and we are seeking to enter into long-term contracts with new customers for such purposes.

Old Harbour, Jamaica – Our Old Harbour Facility commenced commercial operations in June 2019. The Old Harbour Facility is an offshore facility with storage and regasification equipment provided via FSRU. The offshore design eliminates the need for onshore infrastructure including storage tanks. It is capable of processing approximately six million gallons of LNG (500,000 MMBtu) per day. The Old Harbour Facility is supplying gas to a 190MW gas-fired power plant (the “Old Harbour Power Plant”) owned and operated by South Jamaica Power Company Limited (“SJPC”) pursuant to a long-term contract for natural gas equivalent to approximately 380,000 gallons of LNG (31,400 MMBtu) per day. The Old Harbour Facility is also supplying gas to our dual-fired combined heat and power (“CHP”) facility in Clarendon, Jamaica (the “CHP Plant”), which we constructed, and which commenced commercial operations on March 3, 2020. We have total aggregate contracted volumes of approximately 702,000 gallons of LNG (58,000 MMBtu) per day at our Old Harbour Facility with a weighted average contract length of 18 years as of December 31, 2021. We have the ability to service other potential customers with the excess capacity of the Old Harbour Facility, and we are seeking to enter into long-term contracts with new customers for such purposes.

San Juan, Puerto Rico – 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 the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. In addition, it supplies natural gas to Units 5 and 6 of the San Juan combined cycle power plant (the “PREPA San Juan Power Plant”), which are owned and operated by the Puerto Rico Electric Power Authority (“PREPA”), a public instrumentality of the government of Puerto Rico. We converted Units 5 and 6, which together have a capacity of 440MW, to use natural gas as fuel and expect to supply both Units 5 and 6 with approximately 830,000 gallons of LNG (68,595 MMBtu) per day.

Sergipe, Brazil – The Sergipe Facility and Sergipe Power Plant (as defined herein), acquired as part of the Hygo Merger (as defined herein) and located near Aracaju, the state capital of Sergipe, Brazil, commenced commercial operations in March 2020. It is Brazil’s first private-sector LNG-to-power project and an important component for the country’s energy supply. The Sergipe Facility and Sergipe Power Plant are owned and operated by Centrais Elétricas de Sergipe S.A. (“CELSE”), which is part of our 50/50 joint venture with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., one of the largest independent private thermoelectric energy generators in the northeast region of Brazil. The Sergipe Facility is capable of processing up to 790,000 MMBtu/d 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 the 1.5GW combined cycle power plant located near Aracaju, the state capital of Sergipe, Brazil (the “Sergipe Power Plant”), at full dispatch. 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 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), including investment grade counterparties, for a period of 25 years. CELSE is capable of generating incremental earnings through the sale of power via Emergency Security (Segurança Energética) dispatch notices from the Sergipe Power Plant, as occurred during the summer of 2021 to meet the country’s power needs during periods of rainfall shortage. Additionally, we, together with our joint venture partner, Ebrasil, can elect to produce merchant power at the Sergipe Power Plant in any period in which power is not being produced pursuant to the PPAs, and sell the power into the electricity grid at spot prices, subject to local regulatory approval.

We also own expansion rights with respect to the Sergipe Power Plant, which are owned by Centrais Elétricas Barra 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.

La Paz, Baja California Sur, Mexico – Our La Paz Facility commenced operations in the second quarter of 2021. It is an LNG receiving facility located at the Port of Pichilingue in Baja California Sur, Mexico, receiving LNG via ISO containers on an offshore supply vehicle from a nearby vessel. The La Paz Facility is expected to supply approximately 270,000 gallons of LNG (22,300 MMBtu) per day to our gas-fired modular power units located in La Paz (the “La Paz Power Plant”) for approximately 100MW of power following the start of operations. Natural gas supply to the La Paz Power Plant may be increased to approximately 350,000 gallons of LNG (29,000 MMBtu) per day for up to 135MW of power. In addition, on March 26, 2021, we entered into a gas sales agreement with CFEnergia, a subsidiary of Federal Electricity Commission (Comisión Federal de Electricidad), Mexico’s power utility, for the supply of natural gas to power plants located at Punta Prieta and Coromuel in the State of Baja California Sur (the “CFE Plants”). We expect to sell approximately 250,000 gallons of LNG (20,700 MMBtu) per day under the gas sales agreement and are currently delivering LNG via ISO containers on board trucks from the La Paz Facility to the CFE Plants. Similarly, we expect that we will use the La Paz Facility to facilitate the supply of approximately 200,000 gallons of LNG (16,500 MMBtu) per day to regional industrial users and hotels.

Puerto Sandino, Nicaragua – We are constructing an offshore facility in Puerto Sandino, Nicaragua, consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines (the “Puerto Sandino Facility”). The Puerto Sandino Facility is expected to supply gas to a new approximately 300MW natural gas-fired power plant in Puerto Sandino, Nicaragua (the “Nicaragua Power Plant”) that we will own and operate. We have entered into a 25-year power purchase agreement with Nicaragua’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, Brazil – Acquired as part of the Hygo Merger, we are developing our terminal in the State of Pará, Brazil (the “Barcarena Facility”). We anticipate that the Barcarena Facility will be anchored by several large-scale industrial and power customer contracts. 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/d 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 in Pará, Brazil (the “Barcarena Power Plant”). In October 2019, Hygo’s subsidiary, Centrais Elétricas Barcarena S.A. – CELBA 2, was awarded multiple 25-year power purchase agreement to supply electricity to the national electricity grid. The Barcarena Power Plant is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025.

Santa Catarina, Brazil – Acquired as part of the Hygo Merger, our facility in Santa Catarina, Brazil (the “Santa Catarina Facility”) will consist of an FSRU with a processing capacity of approximately 570,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. We have obtained key regulatory and environmental licenses to develop our Santa Catarina Facility on the southern coast of Brazil.

Suape, Brazil – We are developing our LNG terminal in the State 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 the State 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 the Port of Suape, in the city of Ipojuca, State of Pernambuco, Brazil, and own certain 15-year power purchase agreements totaling 288MW for the development of the thermoelectric power plants Pecém II and Camaçari Muricy II, in the State of Bahia, Brazil.  We are seeking to obtain the necessary approvals from the National Agency of Electric Power (Agência Nacional de Energia Elétrica) (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Suape Facility, and to update the technical characteristics in order to develop and construct a 288MW gas-fired power plant and LNG import terminal at the Port of Suape, to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil. As of January 2022, we had commenced power sales under these power purchase agreements via forward selling agreements.

Shannon, Ireland – 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 La Paz Power Plant, the Nicaragua 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”) in Ireland 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.

South Africa – We are in the process of entering into long-term port and land lease agreements in South Africa with the objective of developing an LNG import facility to serve existing power plants, natural gas pipelines and regional industrial clients.

Our LNG Supply Contracts and Liquefaction Assets

LNG Supply Contracts

We entered into two additional long term supply agreements in 2021 for the purchase of LNG between 2022 and 2027. Between these agreements and other agreements signed in 2020, the Company has purchased approximately 648 TBtu for delivery between 2022 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 115 TBtu per year, reducing to approximately 28 TBtu per year by 2028.

As the Company has expanded its terminal footprint with the addition of the Mexico Facility, Puerto Sandino Facility and the Brazil Facilities, the supply position has moved from purely delivered contracts to a mixture of free on board and delivered cargos allowing us to better utilize our acquired fleet and more optimally supply these terminals.

Liquefaction Assets

We constructed the Miami Facility, which commenced full commercial operations in 2016, in fewer than 12 months, at a cost to build of approximately $70 million. The Miami Facility has one liquefaction train, with liquefaction production capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) per day and was 98.2% dispatchable during 2021. The Miami Facility also has three LNG storage tanks, with total capacity of approximately 1,000 cubic meters. The Miami Facility also includes two separate LNG transfer areas capable of serving both truck and rail. For the fiscal year ended December 31, 2021, we delivered approximately 53,428 gallons of LNG (4,416 MMBtu) per day from the Miami Facility pursuant to long-term take-or-pay contracts.

We are currently evaluating the timing of the development of a natural gas liquefaction plant on land we have purchased in the Marcellus area of Pennsylvania (the “Pennsylvania Facility”, and together with the Miami Facility, the “Liquefaction Facilities”). In December 2019, the Pipelines and Hazardous Materials Safety Administration (“PHMSA”) granted a special permit to one of our subsidiaries to ship LNG by rail, which would allow us to transport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels. This permit was schedule to expire on November 30, 2021.  On November 29, 2021, we submitted Special Permit Renewal letter request to PHMSA seeking an extension of the permit until December 1, 2025.  To date, PHMSA has not responded to our letter request.

On July 24, 2020, PHMSA issued a final rule authorizing the nationwide transportation of LNG by rail in DOT–113C120W specification rail tank cars, subject to all applicable requirements and certain additional operational controls. The appeal period for the special permit has expired. However, in November 2021, PHMSA issued a proposed rule to rescind the final rule authorizing nationwide transportation.

Fast LNG (FLNG)

Our existing downstream portfolio coupled with our robust pipeline of new downstream opportunities means we have a strategic need for manufacturing our own LNG and become a vertically-integrated energy-solution provider. Having security of supply and a feedstock insulated from extreme commodity market conditions is critical to our long-term growth. To act on this need, we are developing a mid-scale liquefaction solution called Fast LNG that is cheaper and quicker to deploy than conventional liquefaction projects, and which can be repeated and installed all around the world. Each solution will be comprised of modular liquefaction and processing equipment, which are placed on fixed platforms, jack up rigs or semi-submersible rigs that will be installed offshore in shallow or deep water.

Fast LNG is anchored by key benefits over conventional liquefaction projects.  In particular, we believe installing modular equipment in a shipyard will expedite timelines dramatically. In addition, placing each solution offshore will provide greater access to natural gas and optimized marine logistics.

Fast LNG solutions are also flexible from a commercial standpoint, as they can act as tolling facilities (where we are not the offtaker of the LNG), manufacturing facilities (where we transport produced LNG directly to our downstream customers), or a hybrid (where NFE tolls and offtakes a portion of LNG produced). This flexibility enables us to take advantage of numerous opportunities around the world and present the most optimal commercial arrangements for us and our counterparties.

We are developing and constructing our first Fast LNG solution. We have purchased three jack-up rigs and are preparing our liquefaction module installation. Once completed, we expect to deploy our first Fast LNG solution internationally pursuant to a definitive commercial agreement with a large multinational counterparty. We expect to commit to constructing additional Fast LNG solutions in 2022.

Our Shipping Assets

Floating Storage and Regasification Units (FSRUs)

We commercially operate seven FSRUs, one of which is chartered from a third party. The ships range in size from 125,000 cubic meters to 170,000 cubic meters and are critical to service the demands of our large-scale downstream customers. FSRUs are generally less costly and substantially faster to deploy compared to the construction and development of land-based LNG regassification and storage facilities. The FSRUs are employed on long-term contracts to both third parties and our subsidiaries. As third-party charters expire, we plan to employ the ships internally for regasification needs at our Facilities and/or newly developed projects.

LNG Carriers (LNGCs)

We commercially operate eleven LNGCs, six of which are chartered from third parties. We also own an additional LNGC, which is currently in lay-up. The ships range in size from 6,500 cubic meters to 174,000 cubic meters and transport cargoes from ports, FSRUs and FSUs to other downstream facilities. We employ our LNGCs on time charters to both third parties and our subsidiaries and occasionally employ them as FSUs depending on our needs.

Our Current Customers

Our downstream customers are, and we expect future customers to be, a mix of power, transportation and industrial users of natural gas and LNG, as well as local power generation, distribution companies, including private and governmental owned or controlled. We seek to substantially reduce our customers’ fuel costs while providing them with a cleaner-burning, more environmentally-friendly fuel source. We also intend to sell power and steam directly to some of our customers. In addition, we provide development services to some customers for the conversion or development of natural gas-fired power generation in connection with long-term agreements to supply natural gas or LNG to the customer.

We seek to enter into long-term take-or-pay contracts to deliver natural gas or LNG. Pricing for any particular customer depends on the size of the customer, purchased volume, the customer’s credit profile, the complexity of the delivery and the infrastructure required to deliver it.

For the year ended December 31, 2020, revenue from three significant customers constituted 88% of the total revenue. In 2021, customer concentration has improved considerably, and those three customers constituted 32% of total revenue.

We have several contracts with government-affiliated entities in the countries in which we operate. In Jamaica, we have gas sales agreements with JPS and SJPC, which have remaining terms of approximately 17.3 years, with mutual options to extend, subject to certain conditions. The Jamaica gas sales agreements represent approximately 50% of Jamaica’s installed power capacity and sales of approximately 955,000 gallons of LNG (79,000 MMBtu) per day at full commercial operations. The aggregate minimum quantities we are required to deliver, and our counterparties are required to purchase, under the Jamaica gas sales agreements initially, total approximately 56,200 MMBtu per day.  In Puerto Rico, we have entered into a fuel sale and purchase agreement with PREPA, pursuant to which we expect PREPA to purchase 830,000 gallons of LNG (68,595 MMBtu) per day in connection with the operation of both Units 5 and 6 of the PREPA San Juan Power Plant. In Mexico, we have entered into a gas sales agreement with CFEnergia for the supply of natural gas to CFE Plants. We expect to sell approximately 250,000 gallons of LNG (20,700 MMBtu) per day under the gas sales agreement and are currently delivering LNG via ISO containers on board trucks from the La Paz Facility to the CFE Plants. In Nicaragua, we have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, some of which are wholly or partially owned or controlled by governmental entities.  In Brazil, we have entered into various power purchase agreements with local distribution companies, some of which are wholly or partially owned or controlled by governmental entities.

Bogue Power Plant

We have executed a 22-year agreement to supply JPS’s 145MW Bogue Power Plant in Montego Bay, Jamaica, with natural gas equivalent to approximately 310,000 gallons of LNG (25,600 MMBtu). The Bogue Power Plant has been converted to run on natural gas as well as ADO as backup fuel.

Old Harbour Power Plant

We have executed an agreement to supply SJPC’s 190MW Old Harbour Power Plant in Old Harbour, Jamaica with natural gas equivalent to approximately 380,000 gallons of LNG (31,400 MMBtu) per day, and back-up ADO, for 20 years. The Old Harbour Power Plant is an approximately 190MW capacity dual-fuel plant owned by SJPC.

Jamalco CHP Plant

We have executed a suite of agreements in connection with the CHP Plant, including a 20-year SSA to supply a joint venture between General Alumina Jamaica (“GAJ”), a subsidiary of Noble Group, and Clarendon Alumina Production Limited, an entity owned by the Government of Jamaica (“Jamalco”).  We are providing Jamalco with steam for use in its alumina refinery operations, and we have a 20-year PPA to supply electricity to JPS. The CHP Plant is a 150MW combined heat and power plant and is fueled by natural gas, with the ability to run on ADO as a backup fuel source.

PREPA San Juan Power Plant

On March 5, 2019, we entered into an agreement with PREPA for the conversion of Units 5 and 6 of the PREPA San Juan Power Plant to use natural gas, which together have a capacity of 440MW, and the supply of natural gas fuel to Units 5 and 6 with approximately 830,000 gallons of LNG (68,595 MMBtu) per day. The natural gas supply agreement has an initial natural gas supply term of 5 years from the beginning of commercial operations of the Units and has three separate 5-year extensions that are exercisable at PREPA’s option. We have supplied natural gas to Units 5 and 6 since April 2020.

Nicaragua Power Plant

On February 13, 2020, we entered into a 25-year power purchase agreement to supply electricity to Nicaragua’s electricity distribution companies, and we are in the process of constructing a natural gas-fired power plant with a capacity of approximately 300MW in connection with these power purchase agreements.

Alunorte Alumina Refinery

On December 13, 2021, we entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility. The Alunorte Alumina Refinery requires conversion to use natural gas.

Industrial End-User Sales

We have entered into multiple long-term contracts to sell LNG or natural gas directly to industrial end-users in Jamaica, Puerto Rico, Brazil, and Mexico. To fulfill the requirements of our end-user customers, we transport LNG through our Miami Facility in the United States or from third parties in market purchases and deliver such LNG directly to customers’ facilities or to our for regasification or power generation on customer’s sites.

Competition

In marketing LNG and natural gas, we compete for sales of LNG and natural gas primarily with LNG distribution companies who focus on sales of LNG without our integrated approach which includes development services and power. We also compete with a variety of natural gas marketers who may have affiliated distribution partners, including:

• major integrated marketers whose advantages include large amounts of capital and the ability to offer a wide range of services and market numerous products other than natural gas;

• producer marketers who sell natural gas they produce or which is produced by an affiliated company;

• small geographically focused marketers who focus their marketing on the geographic area in which their affiliated distributor operates; and

• aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.

Despite these competitors, we do not expect to experience significant competition for our LNG logistics services with respect to the Facilities to the extent we have entered into fixed GSAs or other long-term agreements we serve through the Facilities. If and when we have to replace our agreements with our counterparties, we may compete with other then-existing LNG logistics companies for these customers.

In purchasing LNG, we compete for supplies of LNG with:

• large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources;

• oil and gas producers who sell or control LNG derived from their international oil and gas properties; and

• purchasers located in other countries where prevailing market prices can be substantially different from those in the United States.

Government Regulation

Our infrastructure business and operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws, as well as foreign regulations and laws. These laws require, among other things, consultations with appropriate federal, state and other agencies and that we obtain, maintain and comply with applicable permits, approvals and other authorizations for the siting and conduct of our business. These regulatory requirements increase our costs of operations and construction, and failure to comply with such laws could result in consequences such as substantial penalties and/or the issuance of administrative orders to cease or restrict operations until we are in compliance.

DOE Export

The Department of Energy (“DOE”) issued orders authorizing us, through our subsidiary, American LNG Marketing LLC or its designee, to export up to a combined total of the equivalent of 60,000 mtpa (approximately 3.02 Bcf/yr) of domestically produced LNG by tanker from the Miami Facility to Free Trade Agreement (“FTA”) countries for a 20-year term and to non-FTA countries for a 20-year term under contracts with terms of two years or longer. The 20-year term of the authorizations commenced on February 5, 2016, the date of first export from the Miami Facility. The DOE has also authorized American LNG Marketing LLC or its designee to export LNG from the Miami Facility to FTA and non-FTA countries under short-term (less than two years) agreements or on a spot cargo basis. Any LNG exported under the short-term authorization would be counted toward the quantity authorized under the long-term authorizations. These authorizations from the DOE are only applicable to exports of LNG produced at our Miami Facility, and exports of LNG from a liquefaction facility other than the Miami Facility (such as the Pennsylvania Facility) to FTA and/or non-FTA countries will require us to obtain new authorizations from the DOE.

The DOE issued an order authorizing us, through our subsidiary, NFEnergía LLC, to import LNG from various international sources by vessel at our San Juan Facility up to a total volume equivalent to 80 Bcf of natural gas over the two-year period beginning March 26, 2020. NFEnergía LLC must renew its authorization every two years. Imports of LNG are deemed to be consistent with the public interest under Section 3 of the Natural Gas Act (“NGA”) and applications for such imports must be granted without modification or delay.

FERC Authorization

The Federal Energy Regulatory Commission (“FERC”) regulates the siting, construction and operation of “LNG terminals” under NGA Section 3. In consultation with our outside counsel and, where appropriate, FERC staff, we have designed and constructed our U.S. facilities so that they do not meet the statutory definition of an “LNG terminal” as interpreted by FERC pursuant to its case law. On June 18, 2020, we received an order from FERC which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020, and requested that FERC act expeditiously. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021, FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19 and July 15 orders with the United States Court of the Appeals for the District of Columbia Circuit. To date, no other party has sought review of FERC’s orders.  While our petitions for review are pending, and in order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

Pipeline and Hazardous Materials Safety Administration

Many LNG facilities are also subject to regulation by the Department of Transportation (“DOT”), through PHMSA; PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of “pipeline facilities,” which PHMSA has defined to include certain LNG facilities that liquefy, store, transfer or vaporize natural gas transported by pipeline in interstate or foreign commerce. PHMSA has promulgated detailed, comprehensive regulations governing LNG facilities under its jurisdiction at Title 49, Part 193 of the United States Code of Federal Regulations. These regulations address LNG facility siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. Variances from these regulations may require obtaining a special permit from PHMSA, the issuance of which is subject to public notice and comment and consultation with other federal agencies, which could result in delays, perhaps substantial in length, to the construction of our facilities where such variances are needed; additionally, PHMSA may condition, revoke, suspend or modify the special permits it issues.

In December 2019, PHMSA granted a special permit to one of our subsidiaries to ship LNG by rail, which would allow us to transport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels. On July 24, 2020, PHMSA issued a final rule authorizing the nationwide transportation of LNG by rail in DOT–113C120W specification rail tank cars, subject to all applicable requirements and certain additional operational controls. The appeal period for the special permit has expired. However, in November 2021, PHMSA issued a proposed rule to rescind the final rule authorizing nationwide transportation. We have the ability to transport LNG from our Pennsylvania Facility via truck, and this logistical solution is available to us should we be unable to transport by rail.

Environmental Regulation

Our infrastructure and operations are subject to various international, federal, state and local laws and regulations as well as foreign laws and regulations relating to the protection of the environment, natural resources and human health. These laws and regulations may require the installation of controls on emissions and structures to prevent or mitigate any potential harm to human health and the environment or require certain protocols to be in place for mitigating or responding to accidental or intentional incidents at certain facilities. These laws and regulations may also lead to substantial penalties for noncompliance and substantial liabilities for incidents arising out of the operation of our facilities. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.

Other local laws and regulations, including local zoning laws, critical infrastructure regulations and fire protection codes, may also affect where and how we operate.

The costs of compliance with these requirements are not expected to have a material adverse effect on our business, financial condition or results of operations.

Environmental Regulation in Mexico

Mexican law comprehensively regulates all aspects of the receipt, delivery, storage and re-vaporization of LNG as well as the generation and transmission of electricity in Mexico. Various federal agencies in Mexico regulate these activities, including the Department of Environment and Natural Resources, Department of Communication and Transportation, Energy Regulatory Commission, and the Agency for Safety, Energy & Environment, which issues permits for all activities associated with the use of fossil fuels. State and local agencies also regulate these activities, issuing permits and authorizing the use of property for such purposes. In order to be able to obtain various permits for operations under Mexican law, the project must first complete environmental and social impact analyses according to the requirements of Mexican law. Each such impact analysis is subject to further appeal. Mexican law allows the governmental entities and, in certain cases, individuals to pursue claims against violators of environmental laws or permits issued pursuant to such laws. In March 2021, an amendment to the Mexican Power Industry Law (Ley de la Industria Electrica) was published which would reduce the dispatch priority of privately-owned power plants compared to state-owned power plants in Mexico. The amendment is being challenged as unconstitutional, and a judge recently awarded a temporary injunction halting the implementation of the amendment. However, if the amendment is enforced against us, it could negatively affect our plant’s dispatch and our revenue and results of operations.

Environmental Regulation in Jamaica

Our operations in Jamaica are governed by various environmental laws and regulations. These laws and regulations are largely implemented through the National Environment and Planning Agency and cover discharges of pollutants, regulation of air emissions, discharges and treatment of wastewater, storage of fuels, and responses to industrial emergencies involving hazardous materials. The level of environmental regulation in Jamaica has increased in recent years, and the enforcement of environmental laws is becoming more stringent. Compliance has not had a material adverse effect on our business, operations, or financial condition, but we cannot assure you that this will be the case in the future. Jamaica is also in the process of developing a law to govern the receipt, storage, processing and distribution of natural gas, as well as requirements for the licensing, construction, and operation of natural gas facilities and transportation.

Environmental Regulation in Nicaragua

The regulation of activities with the potential to impact the environment in Nicaragua are largely regulated by the Natural Resource and Environment Ministry. Nicaragua regulates many areas of environmental protection. In order to obtain various permits for operations, a project must complete environmental and social impact analyses according to Nicaraguan law. While Nicaragua does not currently have any legislation specifically addressing the receipt, handling, and distribution of natural gas, such laws may be passed in the future.

Environmental Regulation in Ireland

The operation of the facilities will be regulated via additional licenses and consents including from the Environmental Protection Agency (EPA); the Commission for Regulation of Utilities (CRU); the Health and Safety Authority (HSA); and the Local Planning Authority (Kerry Co. Council (KCC)). Additionally, the Shannon Foynes Port Company (SFPC) has statutory jurisdiction over marine activities. The LNG Terminal and Power Plant will also have to operate within the provisions of a number of codes, such as the EirGrid Transmission Network Grid Code, Single Electricity Market Trading and Settlement Code and GNI Code of Operations. We are in the process of applying for all these necessary permits, licenses and consents to build and complete the Ireland Facility.

The issuance of many of these permits may be subject to administrative or judicial challenges, including by non-governmental groups that act on behalf of citizens. We intend to begin construction of the Ireland Facility after we have obtained planning permission and secured contracts with downstream customers for volumes that are sufficient to support the development of the Ireland Facility.

Environmental Regulation in Brazil

Our operations in Brazil are governed by various environmental laws and regulations. These laws and regulations cover social and environmental impacts, air emissions, discharges and treatment of residues, and emergency response, among others. According to Brazilian environmental legislation, the environmental licensing for energy generation activities must follow three stages: a Preliminary License that authorizes the design of the project and the location of the enterprise, an Installation License that authorizes the start of the implementation activities and, an Operating License, which authorizes the actual start of the activity. At each stage, specific environmental plans and studies are required to assess and mitigate the impacts on the environment. In addition, some other authorizations may be required by environmental authorities on a local (municipal), state and federal level, including permits to suppress vegetation, authorization for fauna management, permission to address and/or otherwise mitigate impacts on affected communities, and others.

U.S. and International Maritime Regulations of LNG Vessels

The International Maritime Organization (“IMO”) is the United Nations agency that provides international regulations governing shipping and international maritime trade. The requirements contained in the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”) promulgated by the IMO govern the shipping of our LNG cargoes and the operations of any vessels we use in our operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a policy for safety and environmental protection setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.

Vessels that transport gas, including LNGCs, are also subject to regulation under various international programs such as the International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (the “IGC Code”) published by the IMO. The IGC Code provides a standard for the safe carriage of LNG and certain other liquid gases by prescribing the design and construction standards of vessels involved in such carriage, and includes specific air emissions limits, including on sulfur oxide and nitrogen oxide emissions from ship exhausts.

We contract with leading vessel providers in the LNG industry and look to them to ensure that each of our chartered vessels is in compliance with applicable international and in-country requirements. Nevertheless, the IMO continues to review and introduce new regulations and it is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.

Suppliers and Working Capital

We expect to continue to supply our downstream customers with LNG and natural gas sourced from a combination of long-term, LNG contracts with attractive terms, purchases on the open market, from our Miami Facility, and when completed, our Fast LNG solutions and Pennsylvania Facility.

Due to the nature of our business, we currently carry significant amounts of LNG inventory to meet delivery requirements of customers and assure ourselves of a continuous allotment of goods from suppliers.

Seasonality

Our operations can be affected by seasonal weather, which can temporarily affect our revenues, the delivery of LNG and the construction of our Facilities. For example, activity in the Caribbean is often lower during the North Atlantic hurricane season of June through November, and following a hurricane, activity may decrease further as there may be business interruptions as a result of damage or destruction to our Facilities or the countries in which we operate. The Brazilian electric integrated system is largely dependent on hydro-generated power, which is affected during dry seasons, requiring other sources of power, such as natural gas-fired thermal power station, such as the Sergipe Power Plant, to dispatch more or less based on the amount of the rainfall during any period.  Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. In addition, severe winter weather in the Northeast United States may impact the construction of our Pennsylvania Facility and affect the delivery of feedgas to the facility or LNG to and from ports in the region, among other things. Severe weather in the countries where our Facilities are located may delay completion of our Facilities under development and related infrastructure, adversely affect our operations of our Facilities and affect the markets in which we operate. We are also particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in particular with respect to fleet operations, floating offshore liquefaction units and other infrastructure we may develop in connection with our Fast LNG technology.

Our Insurance Coverage

We maintain customary insurance coverage for our business and operations. Our domestic insurance related to property, equipment, automobile, general liability and workers’ compensation is provided through policies customary for the business and exposures presented, subject to deductibles typical in the industry. Internationally, we also maintain insurance related to property, equipment, automobile, marine, pollution liability, general liability and the portion of workers’ compensation not covered under a governmental program.

We maintain property insurance, including named windstorm and flood, related to the operation of the Miami Facility, San Juan Facility, the La Paz Facility, the Jamaica Facilities and the Sergipe Facility and builders risk insurance at our Facilities under development.

Human Capital

We had 671 full-time employees as of December 31, 2021. We depend upon our skilled workforce to manage, operate and plan for our business. Recruitment and retention of talent across our Company enables growth and innovation across a multitude of corporate initiatives, and this is one of our top priorities.

Our Human Resources team oversees human capital management, including talent attraction and retention, compensation and bonuses, employee relations, employee engagement and training and development in the various countries in which we operate.

Diversity and Inclusion

Our employees are critical to the success of our business. We value the diversity of our workplace and are committed to maintaining culture where our employees feel valued, welcomed and can thrive. We are subject to various federal, state and local laws related to labor and employment, including matters related to workplace discrimination, harassment and unlawful retaliation in the jurisdictions in which we operate. We have developed and published our Code of Business Conduct, which sets out a guideline in connection with these matters and reflects our high expectations for an ethical workplace where employees are treated with dignity and respect. Because labor and employment laws and regulations can differ among the jurisdictions in which we operate, our Code of Business Conduct operates as a guideline for practices, but is not binding or required.

We are advancing our commitments to diversity and inclusion through the following actions, among others:


collecting and analyzing diversity data;


conducting harassment trainings; and
 

expanding employee benefits to include additional health programs such as mental health support and medical concierge services.
 
Employee Health, Safety and Wellness

We are subject to various health, safety, and environmental laws and regulations in the jurisdictions in which we operate. We have developed and published a Health, Safety, Security and Environment (HSSE) Strategic Framework, which sets out a guideline in connection with risk management, education/training, emergency response, incident management, performance measurement and other key programmatic drivers. Because health, safety, and environmental laws and regulations can differ among the jurisdictions in which we operate, our Health, Safety, Security and Environment (HSSE) Strategic Framework operates as a guideline for practices, but is not binding or required. We also have developed and published a contractor safety management handbook for our contractors.

For the year ended December 31, 2021, we achieved zero employee recordable incidents, lost time incidents or fatalities across our operating sites.

Property

We lease space for our offices in New York, New York, Miami, Florida, Rio de Janeiro, Brazil, and in other regions in which we operate. We own the properties on which our Pennsylvania Facility will be located. Additionally, the properties on which our Facilities, the CHP Plant and Miami Facility are located are generally subject to long-term leases and rights-of-way. Our leased properties are subject to various lease terms and expirations.

Formation Transactions and Structure

NFE was formed as a Delaware limited liability company by New Fortress Energy Holdings on August 6, 2018. NFE’s initial public offering closed on February 4, 2019 (the “IPO”). On August 7, 2020, the Company converted New Fortress Energy LLC (“NFE LLC”) from a Delaware limited liability company to a Delaware corporation named New Fortress Energy Inc. (the “Conversion”). Since the IPO, NFE LLC had been a corporation for U.S. federal tax purposes, and converting NFE LLC from a limited liability company to a corporation had no effect on the U.S. federal tax treatment of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately prior to the Conversion were converted into one issued and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of the Company (“Class A common stock”). Class A shares shown on the Company’s consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity.

On June 3, 2020, the Company entered into a mutual agreement (the “Mutual Agreement”) with the members holding the majority voting interest in New Fortress Energy Holdings (“Exchanging Members”) and NFE Sub LLC, a wholly-owned subsidiary of NFE. Pursuant to the Mutual Agreement, the Exchanging Members agreed to deliver a block redemption notice in accordance with the Amended and Restated Limited Liability Company Agreement of NFI LLC (the “NFI LLCA”) with respect to all of the NFI LLC Units, together with an equal number of Class B shares of NFE, that such Exchanging Members indirectly own as members of New Fortress Energy Holdings. Pursuant to the Mutual Agreement, NFE agreed to exercise the Call Right (as defined in the NFI LLCA), pursuant to which NFE would acquire such NFI LLC Units and such Class B shares in exchange for Class A shares of NFE (the “Exchange Transactions”). The Exchange Transactions were completed on June 10, 2020. In connection with the closing of the Exchange Transactions, NFE issued 144,342,572 Class A shares in exchange for an equal number of NFI LLC Units, together with an equal number of Class B shares of NFE. Following the completion of the Exchange Transactions, NFE owns all of the NFI LLC Units directly or indirectly and no Class B shares remain outstanding.

Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s consolidated financial statements. Results of operations for the period prior to the date of the Exchange Transactions, June 10, 2020, was attributed to non-controlling interest based on the Exchanging Members’ interest in NFI; subsequent to the Exchange Transactions, results of operations, excluding results attributable to these Exchanging Members’ prior interest in NFI in NFI; subsequent to the Exchange Transactions, results of operations, excluding results attributable to other investors in non-wholly owned subsidiaries, were recognized as net income or loss attributable to stockholders. Amounts that were attributable to these Exchanging Members’ prior interest in NFI previously shown as non-controlling interest on the Company’s consolidated balance sheets have been reclassified to Class A shares.

On August 7, 2020, the Company converted New Fortress Energy LLC (“NFE LLC”) from a Delaware limited liability company to a Delaware corporation named New Fortress Energy Inc. (the “Conversion”). Since the IPO, NFE LLC had been a corporation for U.S. federal tax purposes, and converting NFE LLC from a limited liability company to a corporation had no effect on the U.S. federal tax treatment of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately prior to the Conversion was converted into one issued and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of NFE (“Class A common stock”). Class A shares shown on the Company’s consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity. As of December 31, 2021, NFE had 206,863,242 Class A common stock outstanding.

The Mergers: Hygo and GMLP Acquisitions

On April 15, 2021, the Company 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 interests of GMLP’s general partner, totaling $251 million. As a result of the Hygo Merger, the Company acquired 50% interest in the Sergipe Power Plant and the Sergipe Facility, as well 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, the Company acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli, each of which are expected to help support the Company’s existing facilities and international project pipeline. The majority of the FSRUs are operating in Brazil, Indonesia, Jamaica and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market.

Sustainability

Since our foundation in 2014, sustainability has been at the core of our mission and vision. We believe that a sustainable future built on positive energy is the way forward. In an effort to advance both our business model and the interests of our stakeholders— including our people, shareholders and investors, partners, the communities we serve, and the wider public—we have established four key sustainability goals: (i) protect and preserve the environment, (ii) empower people worldwide, (iii) invest in communities, and (iv) become a leading provider of carbon-free energy. Certain of our current sustainability initiatives and investments under each of these goals are highlighted below.

Protect and Preserve the Environment

We are committed to our goal to protect and preserve the environment by providing cleaner energy solutions around the world. With our projects, we strive to reduce carbon emissions and increase energy efficiency. By helping our customers convert from traditional fuels such as oil or coal to liquefied natural gas (LNG) as their energy source, we seek to reduce air-polluting emissions of nitrogen oxide (NOx), carbon dioxide (CO2), sulfur oxide (SOx), or fine particulate matter, among others. Moreover, we believe that the use of LNG as a complement to renewable power options is helping transition to a sustainably-sourced energy future.

Empower People Worldwide

We are committed to our goal to provide access to affordable, cleaner energy. To that end, we help our customers customize and implement a complete, seamless LNG energy solution designed to lower their energy costs, reduce their environmental footprint, and improve their energy efficiency, either by converting their existing power generation to LNG or by building brand-new gas-fired facilities. In addition, we seek to provide reliable and efficient supply of LNG to our customers, wherever located, through our established, integrated LNG logistics chain.

Invest in Communities

We are passionate about improving lives and supporting people, especially in the communities where we operate. For example, through our New Fortress Energy Foundation, we seek to strengthen our communities by (i) investing in education to support the next generation of leaders; (ii) providing industry training programs to help create and sustain a well-equipped workforce; and (iii) giving financially to community causes that enhance quality of life, including reducing poverty, hunger, and inequities. As of 2021, we have provided more than 160 higher education scholarships, financial aid to more than 3,800 students, backpacks and supplies to 6,350 students, and supported academic opportunities of more than 16,700 students in the fields of science, technology, engineering and mathematics (STEM). We have donated more than 2,000 trees through the Jamaican government’s national tree planting program. For the holiday season in 2021, we delivered more than 800 care packages to families in Jamaica over Easter and Christmas, meals to 700 families and over 400 toys in disadvantaged areas in Puerto Rico, 400 gift baskets in Nicaragua, and more than 300 gifts to children in Brazil.

Toward a Carbon-Free Future

As we work to reduce emissions for our customers around the world, our long-term goal is for us to reach net zero carbon emissions by 2030 and be one of the world’s leading providers of carbon-free energy. We believe that natural gas remains the most cost-effective and environmentally-friendly complement for intermittent renewable energy, aiding the growth of these technologies. Over time, we believe that low-cost hydrogen will play an increasingly significant role as a carbon-free fuel to support renewables and displace fossil fuels across power, transportation and industrial markets. To that end, we formed a division, which we call Zero, to evaluate promising technologies and pursue initiatives that will position us to capitalize on this emerging industry.

As part of this effort, we intend to develop commercial industrial areas, which we refer to as “Zero Parks,” where we will seek to develop economically compelling hydrogen energy solutions.  In addition, in October 2020, we announced our intention to partner with Long Ridge Energy Terminal and GE Gas Power to transition a power plant to be capable of burning 100% green hydrogen over the next decade, and we made our first hydrogen-related investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost green hydrogen production technology.

Available Information

We are required to file or furnish any annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The SEC maintains an internet website that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC, including this Annual Report, at www.sec.gov.

We also make available free of charge through our website, www.newfortressenergy.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8- K, and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report.

Additionally, we have made our annual Sustainability Report and environmental, social and governance (“ESG”) related documents available on our website, www.newfortressenergy.com, to provide more detailed information regarding our human capital programs and initiatives as well as our efforts to manage ESG issues.

Item 1A.
Risk Factors

An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below. If any of the following risks were to occur, the value of our Class A common stock could be materially adversely affected or our business, financial condition and results of operations could be materially adversely affected and thus indirectly cause the value of our Class A common stock to decline. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business and the value of our Class A common stock. As a result of any of these risks, known or unknown, you may lose all or part of your investment in our Class A common stock. The risks discussed below also include forward-looking statements, and actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement on Forward-Looking Statements”.

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.

Summary Risk Factors

Some of the factors that could materially and adversely affect our business, financial condition, results of operations or prospects include the following:

Risks Related to the Mergers


We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers;

Risks Related to Our Business


We have a limited operating history, which may not be sufficient to evaluate our business and prospects;

We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest;

Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors;

We are subject to various construction risks;

Operation of our infrastructure, facilities and vessels involves significant risks;

We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation;

Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction;

When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project;

Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations;

Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements;

Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects;

Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;

Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess;

Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy;

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers;

We may not be able to purchase or receive physical delivery of LNG or natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPAs and SSAs;

We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve;


We have incurred, and may in the future incur, a significant amount of debt;

Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms;

We may engage in mergers, sales and acquisitions, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value;

Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate;

We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers;

We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect;

Risks Related to the Jurisdictions in Which We Operate


We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate;

Our financial condition and operating results may be adversely affected by foreign exchange fluctuations;

A change in tax laws in any country in which we operate could adversely affect us;

Risks Related to Ownership of Our Class A Common Stock


A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders; and

The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all.

Risks Related to the Mergers

We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers.

In 2021, we consummated the Mergers, which involve the integration of Hygo and GMLP with our existing business. The integration of these businesses is a complex, costly and time-consuming process. The success of the Mergers will depend, in part, on our ability to successfully combine each of Hygo and GMLP, which recently operated as independent companies, with our business and realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from each combination. If we are unable to achieve these objectives within the anticipated time frame, or at all, the anticipated benefits may not be realized fully, or at all, or may take longer to realize than expected and the value of our common stock may be harmed. The integration of each of Hygo and GMLP into our business may result in material challenges, including, without limitation:


managing a larger company;

attracting, motivating and retaining management personnel and other key employees;

the possibility of faulty assumptions underlying expectations regarding the integration process;

retaining existing business and operational relationships and attracting new business and operational relationships;

consolidating corporate and administrative infrastructure and eliminating duplicative operations;

coordinating geographically separate organizations;

unanticipated issues in integrating information technology, communications and other systems; and

unanticipated changes in federal or state laws or regulations.

In the course of the due diligence review of each of Hygo and GMLP that we conducted prior to the consummation of each of the Mergers, we may not have discovered, or may have been unable to quantify, undisclosed liabilities or other issues of Hygo or GMLP and their respective subsidiaries. Moreover, we may not have adequate legal protection from potential liabilities of, or in respect of our acquisition of, Hygo or GMLP, irrespective of whether such potential liabilities were discovered or not. Examples of such undisclosed or potential liabilities or other issues may include, but are not limited to, pending or threatened litigation, regulatory matters, tax liabilities, indemnification of obligations, undisclosed counterparty termination rights, or undisclosed letter of credit or guarantee requirements. Any such undisclosed or potential liabilities or other issues could have an adverse effect on our business, results of operations, financial condition and cash flows. Additionally, as a result of the Mergers, rating agencies may take negative actions against our credit ratings, which may increase our financing costs, including in connection with the financing of the Mergers.

Risks Related to Our Business

We have a limited operating history, which may not be sufficient to evaluate our business and prospects.

We have a limited operating history and track record. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the value of our Class A common stock. We commenced operations on February 25, 2014, and we had net losses of approximately $78.2 million in 2018, $204.3 million in 2019, and $264.0 million in 2020. In 2021, we recognized income of $92.7 million. Our limited operating history also means that we continue to develop and implement our strategies, policies and procedures, including those related to project development planning, operational supply chain planning, data privacy and other matters. We cannot give you any assurance that our strategy will be successful or that we will be able to implement our strategy on a timely basis, if at all, or achieve our internal model or that our assumptions will be accurate. Furthermore, in 2021, we consummated the Mergers, which involve the integration of Hygo and GMLP with our existing business.  Our operating history prior to 2021 does not reflect the combination of these businesses and our limited operating history may not accurately reflect our business following consummation of the Mergers.  The success of our business will depend, in part, on our ability to successfully combine each of Hygo and GMLP, which recently operated as independent companies, with our business and realize the anticipated benefits, failure of which could result in a material adverse effect upon our operations and business. See “—We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers.”

We may not be profitable for an indeterminate period of time.

We have a limited operating history and did not commence revenue-generating activities until 2016. We achieved profitability for the first time in 2021. Several of our projects have not reached commercial operations and we will not receive any material increase in operating cash flows until a project is completed.  Even if completed, we may construct facilities to capture anticipated future energy consumption growth in a region in which such growth does not materialize.  For example, the purchase of the project company holding the rights to develop and operate the Ireland Facility (as defined herein) is subject to several contingencies, many of which are beyond our control and could cause us not to acquire the remaining interests of the project company or cause a delay in the construction of our Ireland Facility. We have made and will continue to make significant initial investments to complete construction and begin operations of each of our Facilities, power plants and Liquefaction Facilities, as well as all related infrastructure, and we will need to make significant additional investments to develop, improve and operate them. We also expect to make significant expenditures and investments in identifying, acquiring and/or developing other future projects, including in connection with the Mergers and new technologies. We expect to incur significant expenses in connection with the growth of our business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel, as well as any technologies we develop. We will need to raise significant additional debt and equity funding to achieve our goals. We cannot assure you that we will be able to sustain such profitability in the future. Our failure to achieve or sustain profitability would have a material adverse effect on our business.

Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors.

Our business strategy relies on a variety of factors, including our ability to successfully market LNG, natural gas, steam, and power to end-users, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in the countries where we operate, expand our projects and operations to other countries where we do not currently operate, and successfully integrate Hygo and GMLP into our business. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control, including, among others:


inability to achieve our target costs for the purchase, liquefaction and export of natural gas and/or LNG and our target pricing for long-term contracts;

failure to develop strategic relationships;

failure to develop cost-effective logistics solutions;

failure to manage expanding operations in the projected timeframe;

inability to develop infrastructure in a timely and cost-effective manner;

increases in competition which could increase our costs and undermine our profits;

inability to source LNG and/or natural gas in sufficient quantities and/or at economically attractive prices;

failure to anticipate and adapt to new trends in the energy sector;

increases in operating costs, including the need for capital improvements, insurance premiums, general taxes, real estate taxes and utilities, affecting our profit margins;

failure to win new bids or contracts on the terms, size and within the time frame we need to execute our business strategy;


failure to obtain required governmental and regulatory approvals for the construction and operation of these projects and other relevant approvals;

unfavorable laws and regulations, changes in laws or unfavorable interpretation or application of laws and regulations; and

uncertainty regarding the timing, pace and extent of an economic recovery in the United States, the other jurisdictions in which we operate and elsewhere, which in turn will likely affect demand for crude oil and natural gas.

Furthermore, as part of our business strategy, we target customers who have not been traditional purchasers of natural gas, including customers in developing countries, and these customers may have greater credit risk than typical natural gas purchasers. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance.

Our strategy may evolve over time. Our future ability to execute our business strategy is uncertain, and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our ability to execute our business strategy and adversely affect our business, financial condition and results of operations.

We are subject to various construction risks.

We are involved in the development of complex small, medium and large-scale engineering and construction projects, including our Facilities, Liquefaction Facilities, power plants, and related infrastructure, which are often developed in multiple stages involving commercial and governmental negotiations, site planning, due diligence, permit requests, environmental impact studies, permit applications and review, marine logistics planning and transportation and end-user delivery logistics. In addition to our facilities, these infrastructure projects can include the development and construction of facilities as part of our customer contracts. Projects of this type are subject to a number of risks including, among others:


engineering, environmental or geological problems;

shortages or delays in the delivery of equipment and supplies;

government or regulatory approvals, permits or other authorizations;

failure to meet technical specifications or adjustments being required based on testing or commissioning;

construction accidents that could result in personal injury or loss of life;

lack of adequate and qualified personnel to execute the project;

weather interference; and

potential labor shortages, work stoppages or labor union disputes.

Furthermore, because of the nature of our infrastructure, we are dependent on interconnection with transmission systems and other infrastructure projects of third parties, including our customers, and/or governmental entities. Such third-party projects can be greenfield or brownfield projects, including modifications to existing infrastructure or increases in capacity to existing facilities, among others, and are subject to various construction risks.  Delays from such third parties or governmental entities could prevent connection to our projects and generate delays in our ability to develop our own projects.  In addition, a primary focus of our business is the development of projects in foreign jurisdictions, including in locations where we have no prior development experience, and we expect to continue expanding into new jurisdictions in the future. These risks can be increased in jurisdictions where legal processes, language differences, cultural expectations, currency exchange requirements, political relations with the U.S. government, changes in the political views and structure, government representatives, new regulations, regulatory reviews, employment laws and diligence requirements can make it more difficult, time-consuming and expensive to develop a project.  See “–Risks Related to the Jurisdictions in which we Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate”.

The occurrence of any one of these factors, whatever the cause, could result in unforeseen delays or cost overruns to our projects.  Delays in the development beyond our estimated timelines, or amendments or change orders to our construction contracts, could result in increases to our development costs beyond our original estimates, which could require us to obtain additional financing or funding and could make the project less profitable than originally estimated or possibly not profitable at all. Further, any such delays could cause a delay in our anticipated receipt of revenues, a loss of one or more customers in the event of significant delays, and our inability to meet milestones or conditions precedents in our customer contracts, which could lead to delay penalties and potentially a termination of agreements with our customers. We have experienced time delays and cost overruns in the construction and development of our projects as a result of the occurrence of various of the above factors, and no assurance can be given that we will not continue to experience in the future similar events, any of which could have a material adverse effect on our business, operating results, cash flows and liquidity.

Operation of our infrastructure, facilities and vessels involves significant risks.

Our existing infrastructure, facilities and vessels and expected future operations and businesses face operational risks, including, but not limited to, the following:


performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

breakdowns or failures of equipment or shortages or delays in the delivery of supplies;

operational errors by trucks, including trucking accidents while transporting natural gas, LNG or any other chemical or hazardous substance;

tankers or tug operators;

operational errors by us or any contracted facility, port or other operator of related infrastructure;

failure to maintain the required government or regulatory approvals, permits or other authorizations;

accidents that could result in personal injury or loss of life;

lack of adequate and qualified personnel;

potential labor shortages, work stoppages or labor union disputes;

weather-related or natural disaster interruptions of operations;

pollution or environmental contamination affecting operation;

inability, or failure, of any counterparty to any facility-related agreements to perform their contractual obligations;

decreased demand by our customers, including as a result of the COVID-19 pandemic; and

planned and unplanned power outages or failures to supply due to scheduled or unscheduled maintenance.

Furthermore, we are subject to risks related to marine LNG operations with respect to our FSRUs and LNG carriers, which operations are complex and technically challenging and subject to mechanical risks and problems. Marine LNG operations are subject to a variety of risks, including, among others, marine disasters, piracy, bad weather, mechanical failures, environmental accidents, epidemics, grounding, fire, explosions and collisions, human error, and war and terrorism. An accident involving our cargoes or any of our chartered vessels could result in death or injury to persons, loss of property or environmental damage; delays in the delivery of cargo; loss of revenues; termination of charter contracts; governmental fines, penalties or restrictions on conducting business; higher insurance rates; and damage to our reputation and customer relationships generally. Any of these circumstances or events could increase our costs or lower our revenues. If our chartered vessels suffer damage as a result of such an incident, they may need to be repaired. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built and result in higher than anticipated operating expenses or require additional capital expenditures. The loss of earnings while these vessels are being repaired would decrease our results of operations. If a vessel we charter were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage could have a material adverse effect on our reputation, our business, our results of operations and cash flows and weaken our financial condition. Our marine operating expenses depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond its control, such as the overall economic impacts caused by the global COVID-19 outbreak. Factors such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements could also increase operating expenditures. Future increases to operational costs are likely to occur. If costs rise, they could materially and adversely affect our results of operations. In addition, operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm our business, financial condition and results of operations.

We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, our facilities or assets.

We depend on third-party contractors, operators and suppliers.

We rely on third-party contractors, equipment manufacturers, suppliers and operators for the development, construction and operation of our projects and assets. We have not yet entered into binding contracts for the construction, development and operation of all of our facilities and assets, and we cannot assure you that we will be able to enter into the contracts required on commercially favorable terms, if at all, which could expose us to fluctuations in pricing and potential changes to our planned schedule. If we are unable to enter into favorable contracts, we may not be able to construct and operate these assets as expected, or at all. Furthermore, these agreements are the result of arms-length negotiations and subject to change.  There can be no assurance that contractors and suppliers will perform their obligations successfully under their agreements with us.  If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. For example, each of our vessels is operated and maintained by GLNG or its affiliates pursuant to ship management agreements. Any failure by GLNG or its affiliates in the operation of our vessels could have an adverse effect on our maritime operations and could result in our failure to deliver LNG to our customers as required under our customer agreements. Although some agreements may provide for liquidated damages if the contractor or supplier fails to perform in the manner required with respect to its obligations, the events that trigger such liquidated damages may delay or impair the completion or operation of the facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment, including, among others, any covenants or obligations by us to pay liquidated damages or penalties under our agreements with our customers, development services, the supply of natural gas, LNG or steam and the supply of power, as well as increased expenses or reduced revenue. Such liquidated damages may also be subject to caps on liability, and we may not have full protection to seek payment from our contractors to compensate us for such payments and other consequences. We may hire contractors to perform work in jurisdictions where they do not have previous experience, or contractors we have not previously hired to perform work in jurisdictions we are beginning to develop, which may lead to such contractors being unable to perform according to its respective agreement. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. If we are unable to construct and commission our facilities and assets as expected, or, when and if constructed, they do not accomplish our goals, or if we experience delays or cost overruns in construction, our business, operating results, cash flows and liquidity could be materially and adversely affected.

We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation

Our business is highly regulated and subject to numerous governmental laws, rules, regulations and requires permits, authorizations and various governmental and agency approvals, in the various jurisdictions in which we operate, that impose various restrictions and obligations that may have material effects on our business and results of operations. Each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the federal, state or local level, or by new or modified regulations that may be implemented under existing law. The nature and extent of any changes in these laws, rules, regulations and permits may be unpredictable, have retroactive effects, and may have material effects on our business. Future legislation and regulations or changes in existing legislation and regulations, or interpretations thereof, such as those relating to the liquefaction, storage, or regasification of LNG, or its transportation could cause additional expenditures, restrictions and delays in connection with our operations as well as other future projects, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

In addition, these rules and regulation are subject to decision, administration and implementation by various governmental agencies and bodies, which take actions or decisions that adversely affect our business or operations.  For example, in March 2021, an amendment to the Mexican Power Industry Law (Ley de la Industria Electrica) was published which would reduce the dispatch priority of privately-owned power plants compared to state-owned power plants in Mexico. The amendment was determined to be unconstitutional by a Mexican court, but the administration may propose a constitutional amendment to implement the change. More recently, on May 4, 2021, an amendment to the Mexican Hydrocarbons Law (Ley de Hidrocarburos) was published which would negatively impact our permits in Mexico. This amendment is being challenged as unconstitutional. If the amendment is enforced against us, it could negatively affect our permitting applications, our revenue and results of operations. If either amendment is enforced against us, it could negatively affect our plant’s dispatch and our revenue and results of operations. In addition, the Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the New Regulatory Framework (Lei do Novo Modelo do Setor Elétrico). Challenges to the constitutionality of the New Regulatory Framework are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal), although preliminary injunctions have been dismissed. It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Regulatory Framework were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including our Brazilian business and operations. Due to the duration of the lawsuit, it is possible that the Brazilian Federal Supreme Court will not give retroactive effect to its decision, but rather preserve the validity of past acts applying a judicial practice known as modulation of effects. Revised, reinterpreted or additional laws and regulations that delay our ability to obtain permits necessary to commence operations or that result in increased compliance costs or additional operating costs and restrictions could have an adverse effect on our business, the ability to expand our business, including into new markets, results of operations, financial condition, liquidity and prospects.

In the United States and Puerto Rico, approvals of the DOE under Section 3 of the NGA, as well as several other material governmental and regulatory permits, approvals and authorizations, including under the CAA and the CWA and their state analogues, may be required in order to construct and operate an LNG facility and export LNG. Permits, approvals and authorizations obtained from the DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional requirements may be imposed. Certain federal permitting processes may trigger the requirements of the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions that have the potential to significantly impact the environment. Compliance with NEPA may extend the time and/or increase the costs for obtaining necessary governmental approvals associated with our operations and create independent risk of legal challenges to the adequacy of the NEPA analysis, which could result in delays that may adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and profitability. On July 15, 2020, the White House Council on Environmental Quality issued a final rule revising its NEPA regulations. These regulations have taken legal effect, and although they have been challenged in court, they have not been stayed. The Council on Environmental Quality has announced that it is engaged in an ongoing and comprehensive review of the revised regulations and is assessing whether and how the Council may ultimately undertake a new rulemaking to revise the regulations. The impacts of any such future revisions that may be adopted are uncertain and indeterminable for the foreseeable future. On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020, and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which is September 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 the March 19, 2021, FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021.  We have filed petitions for review of FERC’s March 19, 2021, and July 15, 2021, orders with the United States Court of the Appeals for the District of Columbia Circuit.  To date, no other party has sought review of FERC’s orders.  While our petitions for review are pending and in order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

We may not comply with each of these requirements in the future, or at all times, including any changes to such laws and regulations or their interpretation. The failure to satisfy any applicable legal requirements may result in the suspension of our operations, the imposition of fines and/or remedial measures, suspension or termination of permits or other authorization, as well as potential administrative, civil and criminal penalties, which may significantly increase compliance costs and the need for additional capital expenditures.

Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.

The design, construction and operation of our infrastructure, facilities and businesses, including our FSRUs, FLNGs and LNG carriers, the import and export of LNG and the transportation of natural gas, among others, are highly regulated activities at the national, state and local levels and are subject to various approvals and permits. The process to obtain the permits, approvals and authorizations we need to conduct our business, and the interpretations of those rules, is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We may be unable to obtain such approvals on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations. Many of these permits, approvals and authorizations require public notice and comment before they can be issued, which can lead to delays to respond to such comments, and even potentially to revise the permit application.  We may also be (and have been in select circumstances) subject to local opposition, including citizens groups or non-governmental organizations such as environmental groups, which may create delays and challenges in our permitting process and may attract negative publicity, which may create an adverse impact on our reputation. In addition, such rules change frequently and are often subject to discretionary interpretations, including administrative and judicial challenges by regulators, all of which may make compliance more difficult and may increase the length of time it takes to receive regulatory approval for our operations, particularly in countries where we operate, such as Mexico and Brazil. For example, in Mexico, we have obtained substantially all permits and have commenced terminal operations but are awaiting regassification and transmission permits for our power plant. We do not know the precise date when we will receive the permits we need to commence full commercial operations. Any administrative and judicial challenges can delay and protract the process for obtaining and implementing permits and can also add significant costs and uncertainty. We cannot control the outcome of any review or approval process, including whether or when any such permits and authorizations will be obtained, the terms of their issuance, or possible appeals or other potential interventions by third parties that could interfere with our ability to obtain and maintain such permits and authorizations or the terms thereof. Furthermore, we are developing new technologies and operate in jurisdictions that may lack mature legal and regulatory systems and may experience legal instability, which may be subject to regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to our business and new technology, which can result in difficulties and instability in obtaining or securing required permits or authorizations. There is no assurance that we will obtain and maintain these permits and authorizations on favorable terms, or that we will be able to obtain them on a timely basis, and we may not be able to complete our projects, start or continue our operations, recover our investment in our projects and may be subject to financial penalties or termination under our customer and other agreements, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project.

A key part of our business strategy is to attract new customers by agreeing to finance and develop new facilities, power plants, liquefaction facilities and related infrastructure in order to win new customer contracts for the supply of natural gas, LNG, steam or power. This strategy requires us to invest capital and time to develop a project in exchange for the ability to sell our products and generate fees from customers in the future. When we develop these projects, our required capital expenditure may be significant, and we typically do not generate meaningful fees from customers until the project has commenced commercial operations, which may take a year or more to achieve. If the project is not successfully developed for any reason, we face the risk of not recovering some or all of our invested capital, which may be significant. If the project is successfully developed, we face the risks that our customers may not fulfill their payment obligations or may not fulfill other performance obligations that impact our ability to collect payment. Our customer contracts and development agreements do not fully protect us against this risk and, in some instances, may not provide any meaningful protection from this risk. This risk is heightened in foreign jurisdictions, particularly if our counterparty is a government or government-related entity because any attempt to enforce our contractual or other rights may involve long and costly litigation where the ultimate outcome is uncertain. If we invest capital in a project where we do not receive the payments we expect, we will have less capital to invest in other projects, our liquidity, results of operations and financial condition could be materially and adversely affected, and we could face the inability to comply with the terms of our existing debt or other agreements, which would exacerbate these adverse effects.

Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations.

We have significant working capital requirements, primarily driven by the delay between the purchase of and payment for natural gas and the extended payment terms that we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working capital, we may not be able to pursue our growth strategy, respond to competitive pressures or fund key strategic initiatives, such as the development of our facilities, which may harm our business, financial condition and results of operations.

Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements.

Our business strategy relies upon our ability to successfully market our products to our existing and new customers and enter into or replace our long-term supply and services agreements for the sale of natural gas, LNG, steam and power. If we contract with our customers on short-term contracts, our pricing can be subject to more fluctuations and less favorable terms, and our earnings are likely to become more volatile. An increasing emphasis on the short-term or spot LNG market may in the future require us to enter into contracts based on variable market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in its cash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover its financing costs for related vessels.  Our ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. Their obligations may include certain nomination or operational responsibilities, construction or maintenance of their own facilities which are necessary to enable us to deliver and sell natural gas or LNG, and compliance with certain contractual representations and warranties. Further, adverse economic conditions in our industry increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings. The COVID-19 pandemic could adversely impact our customers through decreased demand for power due to decreased economic activity and tourism, or through the adverse economic impact of the pandemic on their power customers. The impact of the COVID-19 pandemic, including governmental and other third -party responses thereto, on our customers could enhance the risk of nonpayment by such customers under our contracts, which would negatively affect our business, results of operations and financial condition. In particular, JPS and SJPC, which are public utility companies in Jamaica, could be subject to austerity measures imposed on Jamaica by the International Monetary Fund (the “IMF”) and other international lending organizations. Jamaica is currently subject to certain public spending limitations imposed by agreements with the IMF, and any changes under these agreements could limit JPS’s and SJPC’s ability to make payments under their long-term GSAs and, in the case of JPS, its ability to make payments under its PPA, with us. In addition, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under its contracts will be largely dependent upon funding from the Federal Emergency Management Agency or other sources. PREPA’s contracting practices in connection with restoration and repair of PREPA’s electrical grid in Puerto Rico, and the terms of certain of those contracts, have been subject to comment and are the subject of review and hearings by U.S. federal and Puerto Rican governmental entities. In the event that PREPA does not have or does not obtain the funds necessary to satisfy obligations to us under our agreement with PREPA or terminates our agreement prior to the end of the agreed term, our financial condition, results of operations and cash flows could be materially and adversely affected. If any of these customers fails to perform its obligations under its contract for the reasons listed above or for any other reason, our ability to provide products or services and our ability to collect payment could be negatively impacted, which could materially adversely affect our operating results, cash flow and liquidity, even if we were ultimately successful in seeking damages from such customer for a breach of contract.

Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The substantial majority of our anticipated revenue in 2022 will be dependent upon our assets and customers in Jamaica, Brazil and Puerto Rico. Our operations in Jamaica began in October 2016, when our Montego Bay Facility commenced commercial operations, and continue to grow, and our San Juan Facility became fully operational in the third quarter of 2020. We commenced our operations in Brazil in 2021, following the Mergers, and have been operating in Brazil through our joint venture for the Sergipe Facility and the Sergipe Power Plant.  Jamaica, Brazil and Puerto Rico have historically experienced economic volatility and the general condition and performance of their economies, over which we have no control, may affect our business, financial condition and results of operations. Jamaica, Puerto Rico and Brazil are subject to acts of terrorism or sabotage and natural disasters, in particular hurricanes, extreme weather conditions, crime and similar other risks which may negatively impact our operations in the region. See “—Risks Related to the Jurisdictions in which we Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate”. We may also be affected by trade restrictions, such as tariffs or other trade controls. Additionally, tourism is a significant driver of economic activity in the Caribbean and Brazil and directly and indirectly affects local demand for our LNG and therefore our results of operations. Trends in tourism in the Caribbean and Brazil are primarily driven by the economic condition of the tourists’ home country or territory, the condition of their destination, and the availability, affordability and desirability of air travel and cruises. Additionally, unexpected factors could reduce tourism at any time, including local or global economic recessions, terrorism, travel restrictions, pandemics, including the COVID-19 pandemic, severe weather or natural disasters. Due to our current lack of asset and geographic diversification, an adverse development at our Facilities in Jamaica, Brazil or Puerto Rico, in the energy industry or in the economic conditions in Jamaica, Brazil or Puerto Rico, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results.

Our current results of operations and liquidity are, and will continue to be in the near future, substantially dependent upon a limited number of customers, including JPS (as defined herein), SJPC (as defined herein) and PREPA (as defined herein), which have each entered into long-term GSAs and, in the case of JPS, a PPA in relation to the power produced at the CHP Plant (as defined herein), with us, and Jamalco (as defined herein), which has entered into a long-term SSA with us, and which represent a substantial majority of our income. Our operating results are currently contingent on our ability to maintain LNG, natural gas, steam and power sales to these customers. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts.  The loss of any of these customers could have an adverse effect on our revenues and we may not be able to enter into a replacement agreement on terms as favorable as the terminated agreement. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition.

We may not be able to convert our anticipated customer pipeline into binding long-term contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate.

We are actively pursuing a significant number of new contracts for the sale of LNG, natural gas, steam, and power with multiple counterparties in multiple jurisdictions.  Counterparties commemorate their purchasing commitments for these products in various degrees of formality ranging from traditional contracts to less formal arrangements, including non-binding letters of intent, non-binding memorandums of understanding, non-binding term sheets and responding to requests for proposals with potential customers. These agreements and any award following a request for proposals are subject to negotiating final definitive documents. The negotiation process may cause us or our potential counterparty to adjust the material terms of the agreement, including the price, term, schedule and any related development obligations.  We cannot assure you if or when we will enter into binding definitive agreements for transactions initially described in non-binding agreements, and the terms of our binding agreements may differ materially from the terms of the related non-binding agreements. In addition, the effectiveness of our binding agreements can be subject to a number of conditions precedent that may not materialize, rendering such agreements non-effective.  Moreover, while certain of our long-term contracts contain minimum volume commitments, our expected sales to customers under existing contracts may be substantially in excess of such minimum volume commitments. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to nominate in excess of such minimum quantities and to perform their obligations under their respective contracts. Given the variety of sales processes and counterparty acknowledgements of the volumes they will purchase, we sometimes identify potential sales volumes as being either “Committed” or “In Discussion.” “Committed” volumes generally refer to the volumes that management expects to be sold under binding contracts or awards under requests for proposals.  “In Discussion” volumes generally refer to volumes related to potential customers that management is actively negotiating, responding to a request for proposals, or with respect to which management anticipates a request for proposals or competitive bid process to be announced based on discussions with potential customers. Management’s estimations of “Committed” and “In Discussion” volumes may prove to be incorrect.  Accordingly, we cannot assure you that “Committed” or “In Discussion” volumes will result in actual sales, and such volumes should not be used to predict the company’s future results. We may never sign a binding agreement to sell our products to the counterparty, or we may sell much less volume than we estimate, which could result in our inability to generate the revenues and profits we anticipate, having a material adverse effect on our results of operations and financial condition.

Our contracts with our customers are subject to termination under certain circumstances.

Our contracts with our customers contain various termination rights. For example, each of our long-term customer contracts, including the contracts with JPS, SJPC, Jamalco and PREPA, contain various termination rights allowing our customers to terminate the contract, including, without limitation:


upon the occurrence of certain events of force majeure;

if we fail to make available specified scheduled cargo quantities;

the occurrence of certain uncured payment defaults;

the occurrence of an insolvency event;

the occurrence of certain uncured, material breaches; and

if we fail to commence commercial operations or achieve financial close within the agreed timeframes.

We may not be able to replace these contracts on desirable terms, or at all, if they are terminated. Contracts that we enter into in the future may contain similar provisions. If any of our current or future contracts are terminated, such termination could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess.

We operate in the highly competitive industry for LNG and face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies and utilities, in the various markets in which we operate and many of which have been in operation longer than us. Various factors relating to competition may prevent us from entering into new or replacement customer contracts on economically comparable terms to existing customer contracts, or at all, including , among others:


increases in worldwide LNG production capacity and availability of LNG for market supply;

increases in demand for natural gas but at levels below those required to maintain current price equilibrium with respect to supply;

increases in the cost to supply natural gas feedstock to our liquefaction projects;

increases in the cost to supply LNG feedstock to our Facilities;

decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, heavy fuel oil and ADO;

decreases in the price of LNG; and

displacement of LNG or fossil fuels more broadly by alternate fuels or energy sources or technologies (including but not limited to nuclear, wind, solar, biofuels and batteries) in locations where access to these energy sources is not currently available or prevalent.

In addition, we may not be able to successfully execute on our strategy to supply our existing and future customers with LNG produced primarily at our own Liquefaction Facilities upon completion of the Pennsylvania Facility or through our Fast LNG solution. Various competitors have and are developing LNG facilities in other markets, which will compete with our LNG facilities, including our Fast LNG solution. Some of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs, larger and more versatile fleets, and substantially greater financial, technical and marketing resources than we currently possess. We also face competition for the contractors needed to build our facilities and skilled employees. See “—We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us”. The superior resources that some of these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects. We anticipate that an increasing number of marine transportation companies, including many with strong reputations and extensive resources and experience will enter the LNG transportation market and the FSRU market. This increased competition may cause greater price competition for our products. As a result of these factors, we may be unable to expand our relationships with existing customers or to obtain new customers on a favorable basis, if at all, which would have a material adverse effect on our business, results of operations and financial condition.

Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.

Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional or shale natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. The COVID-19 pandemic and actions by Organization of the Petroleum Exporting Countries (“OPEC”) have significantly impacted energy markets, and the price of oil has recently traded at historic low prices, making it a more competitive fuel source to LNG. Potential expansion in the Caribbean, Latin America and other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. In Brazil, hydroelectric power generation is the predominant source of electricity and LNG is one of several other energy sources used to supplement hydroelectric generation. The success of our operations is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to our customers at a lower cost than the cost to deliver other alternative energy sources.

Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean and Latin America, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean, Latin America and other countries where we operate or seek to operate. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to other markets or from or to our competitors’ LNG facilities. Natural gas also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy, which may become available at a lower cost in certain markets. As a result of these and other factors, natural gas may not be a competitive source of energy in the markets we intend to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect our ability to deliver LNG or natural gas to our customers on a commercial basis, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers.

Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors:


additions to competitive regasification capacity in North America, Brazil, Europe, Asia and other markets, which could divert LNG or natural gas from our business;

imposition of tariffs by China or any other jurisdiction on imports of LNG from the United States;

insufficient or oversupply of natural gas liquefaction or export capacity worldwide;


insufficient LNG tanker capacity;

weather conditions and natural disasters;

reduced demand and lower prices for natural gas;

increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

decreased oil and natural gas exploration activities, including shut-ins and possible proration, which may decrease the production of natural gas;

cost improvements that allow competitors to offer LNG regasification services at reduced prices;

changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

political conditions in natural gas producing regions;

adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and

cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

Adverse trends or developments affecting any of these factors, including the timing of the impact of these factors in relation to our purchases and sales of natural gas and LNG could result in increases in the prices we have to pay for natural gas or LNG, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. The COVID-19 pandemic and certain actions by OPEC related to the supply of oil in the market have caused volatility and disruption in the price of oil which may negatively impact our potential customers’ willingness or ability to enter into new contracts for the purchase of natural gas. Additionally, in situations where our supply chain has capacity constraints and as a result we are unable to receive all volumes under our long-term LNG supply agreements, our supplier may sell volumes of LNG in a mitigation sale to third parties. In these cases, the factors above may impact the price and amount we receive under mitigation sales and we may incur losses that would have an adverse impact on our financial condition, results of operations and cash flows. Conversely, current market conditions have made LNG values high relative to long term pricing benchmarks, which has given LNG sellers the potential ability to fail to deliver volumes, pay the contractual penalty, but divert LNG to more profitable markets.  Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amount of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no assurance we will achieve our target cost or pricing goals. In particular, because we have not currently procured fixed-price, long-term LNG supply to meet all future customer demand, increases in LNG prices and/or shortages of LNG supply could adversely affect our profitability. Additionally, we intend to rely on long-term, largely fixed-price contracts for the feedgas that we need in order to manufacture and sell our LNG. Our actual costs and any profit realized on the sale of our LNG may vary from the estimated amounts on which our contracts for feedgas were originally based. There is inherent risk in the estimation process, including significant changes in the demand for and price of LNG as a result of the factors listed above, many of which are outside of our control. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported on or to our tankers and facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.

Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses.

Our strategy is to maintain a manageable balance between LNG purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the LNG purchased by selling LNG for physical delivery to third-party users, such as public utilities, shipping/marine cargo companies, industrial users, railroads, trucking fleets and other potential end-users converting from traditional ADO or oil fuel to natural gas. These strategies cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated supply chain could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when LNG is purchased against one pricing index and sold against a different index. Moreover, we are also exposed to other risks, including price risks on LNG we own, which must be maintained in order to facilitate transportation of the LNG to our customers or to our Facilities. If we were to incur a material loss related to commodity price risks, it could have a material adverse effect on our financial position, results of operations and cash flows.

We may not be able to purchase or receive physical delivery of LNG or natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPAs and SSAs.

Under our GSAs, PPAs and SSAs, we are required to deliver to our customers specified amounts of LNG, natural gas, power and steam, respectively, at specified times and within certain specifications, all of which requires us to obtain sufficient amounts of LNG from third-party LNG suppliers or our own portfolio. We may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may provide a counterparty with the right to terminate its GSA, PPA or SSA, as applicable, or subject us to penalties and indemnification obligations under those agreements. While we have entered into three supply agreements for the purchase of approximately 630 TBtu of LNG between 2022 and 2030, we may need to purchase significant additional LNG volumes to meet our delivery obligations to our downstream customers. Price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items or to sell our inventory of natural gas or LNG at attractive prices. Failure to secure contracts for the purchase of a sufficient amount of LNG or at favorable prices could materially and adversely affect our business, operating results, cash flows and liquidity. Additionally, we are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to replace such contracts or purchase LNG on the spot market or receive a sufficient quantity of LNG in order to satisfy our delivery obligations under our GSAs, PPAs and SSAs or at favorable terms. Under tanker charters, we will be obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased, as our vessels maybe be too small for those obligations. Any such failure to purchase or receive delivery of LNG or natural gas in sufficient quantities could result in our failure to satisfy our obligations to our customers, which could lead to delay penalties and potentially a termination of agreements with our customers. Any such failure to sell our inventory of natural gas or LNG at attractive prices could materially and adversely affect our business, operating results, cash flows and liquidity.

We may not be able to fully utilize the capacity of our FSRUs and other facilities.

Our FSRU facilities have significant excess capacity that is currently not dedicated to a particular anchor customer. Part of our business strategy is to utilize undedicated excess capacity of our FSRU facilities to serve additional downstream customers in the regions in which we operate. However, we have not secured, and we may be unable to secure, commitments for all of our excess capacity. Factors which could cause us to contract less than full capacity include difficulties in negotiations with potential counterparties and factors outside of our control such as the price of and demand for LNG. For example, the owner and operator of the Sergipe Facility, CELSE, has the right to utilize 100% of the capacity at the Sergipe Facility pursuant to the Sergipe FSRU Charter. In order to utilize the excess capacity of the Sergipe Facility, we would need to obtain the consent of CELSE and the senior lenders under CELSE’s financing arrangements. Failure to secure commitments for less than full capacity could impact our future revenues and materially adversely affect our business, financial condition and operating results.

LNG that is processed and/or stored on FSRUs and transported via pipeline is subject to risk of loss or damage.

LNG processed and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, ageing or otherwise. We could bear the risk of loss or damage to all LNG for the period of time during which LNG is stored on an FSRU or is dispatched to a pipeline. Any such disruption to the supply of LNG and natural gas may lead to delays, disruptions or curtailments in the production of power at our Facilities, which could materially and adversely affect our revenues, financial condition and results of operations.

The operation of our vessels is dependent on our ability to deploy our vessels to an NFE terminal or to long-term charters.

Our principal strategy for our FSRU and LNG carriers is to provide steady and reliable shipping, regasification and marine operations to NFE terminals and, to the extent favorable to our business, replace or enter into new long-term carrier time charters for our vessels. Most requirements for new LNG projects continue to be provided on a long-term basis, though the level of spot voyages and short-term time charters of less than 12 months in duration together with medium term charters of up to five years has increased in recent years. This trend is expected to continue as the spot market for LNG expands. More frequent changes to vessel sizes, propulsion technology and emissions profile, together with an increasing desire by charterers to access modern tonnage could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period. As a result, the duration of long-term charters could also decrease over time. We may also face increased difficulty entering into long-term time charters upon the expiration or early termination of our contracts. The process of obtaining long-term charters for FSRUs and LNG carriers is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. If we lose any of our charterers and are unable to re-deploy the related vessel to a NFE terminal or into a new replacement contract for an extended period of time, we will not receive any revenues from that vessel, but we will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt. In addition, it is an event of default under the credit facilities related to all of our vessels if the time charter of any vessel related to any such credit facility is cancelled, rescinded or frustrated and we are unable to secure a suitable replacement charter, post additional security or make certain significant prepayments. Any event of default under GMLP’s credit facilities would result in acceleration of amounts due thereunder.

We rely on tankers and other vessels outside of our fleet for our LNG transportation and transfer.

In addition to our own fleet of vessels, we rely on third-party ocean-going tankers and freight carriers (for ISO containers) for the transportation of LNG and ship-to-ship kits to transfer LNG between ships. We may not be able to successfully enter into contracts or renew existing contracts to charter tankers on favorable terms or at all, which may result in us not being able to meet our obligations. Our ability to enter into contracts or renew existing contracts will depend on prevailing market conditions upon expiration of the contracts governing the leasing or charter of the applicable assets. Therefore, we may be exposed to increased volatility in terms of charter rates and contract provisions. Fluctuations in rates result from changes in the supply of and demand for capacity and changes in the demand for seaborne carriage of commodities. Because the factors affecting the supply and demand are outside of our control and are highly unpredictable, the nature, timing, direction and degree of changes in industry conditions are also unpredictable. Likewise, our counterparties may seek to terminate or renegotiate their charters or leases with us. If we are not able to renew or obtain new charters or leases in direct continuation, or if new charters or leases are entered into at rates substantially above the existing rates or on terms otherwise less favorable compared to existing contractual terms, our business, prospects, financial condition, results of operations and cash flows could be materially adversely affected.

Furthermore, our ability to provide services to our customers could be adversely impacted by shifts in tanker market dynamics, shortages in available cargo carrying capacity, changes in policies and practices such as scheduling, pricing, routes of service and frequency of service, or increases in the cost of fuel, taxes and labor, emissions standards, maritime regulatory changes and other factors not within our control. The availability of the tankers could be delayed to the detriment of our LNG business and our customers because the construction and delivery of LNG tankers require significant capital and long construction lead times. Changes in ocean freight capacity, which are outside our control, could negatively impact our ability to provide natural gas if LNG shipping capacity is adversely impacted and LNG transportation costs increase because we may bear the risk of such increases and may not be able to pass these increases on to our customers.

The operation of ocean-going tankers and kits carries inherent risks. These risks include the possibility of natural disasters; mechanical failures; grounding, fire, explosions and collisions; piracy; human error; epidemics; and war and terrorism. We do not currently maintain a redundant supply of ships, ship-to-ship kits or other equipment. As a result, if our current equipment fails, is unavailable or insufficient to service our LNG purchases, production, or delivery commitments we may need to procure new equipment, which may not be readily available or be expensive to obtain. Any such occurrence could delay the start of operations of facilities we intend to commission, interrupt our existing operations and increase our operating costs. Any of these results could have a material adverse effect on our business, financial condition and operating results.

Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings may decline.

Hire rates for FSRUs and LNG carriers fluctuate over time as a result of changes in the supply-demand balance relating to current and future FSRU and LNG carrier capacity. This supply-demand relationship largely depends on a number of factors outside of our control. For example, driven in part by an increase in LNG production capacity, the market supply particularly of LNG carriers has been increasing. As of February 1, 2022, the LNG carrier order book totaled 153 vessels. We believe that this and any future expansion of the global LNG carrier fleet may have a negative impact on charter hire rates, vessel utilization and vessel values, the impact of which could be amplified if the expansion of LNG production capacity does not keep pace with fleet growth. The LNG market is also closely connected to world natural gas prices and energy markets, which it cannot predict. A substantial or extended decline in demand for natural gas or LNG, including as a result of the spread of COVID-19, could adversely affect our ability to charter or re-charter our vessels at acceptable rates or to acquire and profitably operate new vessels. Accordingly, this could have a material adverse effect on our earnings, financial condition, operating results and prospects.

Vessel values may fluctuate substantially and, if these values are lower at a time when we are attempting to dispose of vessels, we may incur a loss.

Vessel values can fluctuate substantially over time due to a number of different factors, including:


prevailing economic conditions in the natural gas and energy markets;


a substantial or extended decline in demand for LNG;

increases in the supply of vessel capacity without a commensurate increase in demand;

the size and age of a vessel; and

the cost of retrofitting, steel or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.

As our vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on our business and operations if we do not maintain sufficient cash reserves for maintenance and replacement capital expenditures. Moreover, the cost of a replacement vessel would be significant.

During the period a vessel is subject to a charter, we will not be permitted to sell it to take advantage of increases in vessel values without the charterers’ consent. If a charter terminates, we may be unable to re-deploy the affected vessels at attractive rates or for our operations and, rather than continue to incur costs to maintain and finance them, we may seek to dispose of them. When vessel values are low, we may not be able to dispose of vessels at a reasonable price when we wish to sell vessels, and conversely, when vessel values are elevated, we may not be able to acquire additional vessels at attractive prices when we wish to acquire additional vessels, which could adversely affect our business, results of operations, cash flow, and financial condition.

The carrying values of our vessels may not represent their fair market value at any point in time because the market prices of secondhand vessels tend to fluctuate with changes in charter rates and the cost of new build vessels. Our vessels are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Although we did not recognize an impairment charge on any of its vessels for the year ended December 31, 2021, we cannot assure you that we will not recognize impairment losses on our vessels in future years. Any impairment charges incurred as a result of declines in charter rates could negatively affect our business, financial condition, or operating results.

Maritime claimants could arrest our vessels, which could interrupt our cash flow.

If we are in default on certain kinds of obligations related to our vessels, such as those to our lenders, crew members, suppliers of goods and services to our vessels or shippers of cargo, these parties may be entitled to a maritime lien against one or more of our vessels. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in our fleet for claims relating to another of our vessels. The arrest or attachment of one or more of our vessels could interrupt our cash flow and require us to pay to have the arrest lifted. Under some of our present charters, if the vessel is arrested or detained (for as few as 14 days in the case of one of our charters) as a result of a claim against us, we may be in default of our charter and the charterer may terminate the charter. This would negatively impact our revenues and cash flows.

We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve.

We analyze and seek to implement innovative and new technologies that complement our businesses to reduce our costs, achieve efficiencies for our business and our customers and advance our long-term goals, such as our ISO container distribution system, our Fast LNG solution and our green hydrogen project.  The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants.  See “—Our Fast LNG technology is a novel technology that is not yet proven and we may not be able to implement it as planned or at all.” We are also making investments to develop green hydrogen energy technologies as part of our long-term goal to become one of the world’s leading providers of carbon-free energy.  In October 2020, we announced our intention to partner with Long Ridge Energy Terminal and GE Gas Power to transition a power plant to be capable of burning 100% green hydrogen over the next decade, and we made our first hydrogen-related investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost green hydrogen production technology. We continue to develop our ISO container distribution systems in the various markets where we operate. We expect to make additional investments in this field in the future. Because these technologies are innovative, we may be making investments in unproven business strategies and technologies with which we have limited or no prior development or operating experience. As an investor in these technologies, it is also possible that we could be exposed to claims and liabilities, expenses, regulatory challenges and other risks. We may not be able to successfully develop these technologies, and even if we succeed, we may ultimately not be able to realize the time, revenues and cost savings we currently expect to achieve from these strategies, which could adversely affect our financial results.

Technological innovation may impair the economic attractiveness of our projects.

The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although we plan to build out our delivery logistics chain in Northern Pennsylvania using proven technologies such as those currently in operation at our Miami Facility, we do not have any exclusive rights to any of these technologies. In addition, such technologies may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others, which could materially and adversely affect our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

Our Fast LNG technology is a novel technology that is not yet proven and we may not be able to implement it as planned or at all.

We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants.  Our ability to create and maintain a competitive position in the natural gas liquefaction industry may be adversely affected by our inability to effectively implement our Fast LNG technology. We are in the process of designing and constructing our first Fast LNG solution, and are therefore subject to construction risks, risks associated with third-party contracting and service providers, permitting and regulatory risks.   See “—We are subject to various construction risks” and “—We depend on third-party contractors, operators and suppliers”.  Because our Fast LNG technology is a new technology that has not been previously implemented, tested or proven, we are also exposed to unknown and unforeseen risks associated with the development of new technologies, including failure to meet design and engineering specifications, incompatibility of systems, inability to contract or employ third parties with sufficient experience in technologies used or inability by contractors to perform their work, delays and schedule changes, high costs and expenses that may be subject to increase or difficult to anticipate, regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to the technology, and added difficulties in obtaining or securing required permits or authorizations, among others. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction”. The success and profitability of our Fast LNG technology is also dependent on the volatility of the price of natural gas and LNG compared to the related levels of capital spending required to implement the technology. Natural gas and LNG prices have at various times been and may become volatile due to one or more of factors. Volatility or weakness in natural gas or LNG prices could render our LNG procured through Fast LNG too expensive for our customers, and we may not be able to obtain our anticipated return on our investment or make our technology profitable. In addition, we may seek to construct and develop floating offshore liquefaction units as part of our Fast LNG in jurisdictions with increased political, economic, social and legal instability, lack of regulatory clarity of application of laws, rules and regulations to our technology, and could potentially expose us to additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. See “—Risks Related to the Jurisdictions in which we Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate”. Furthermore, as part of our business strategy for Fast LNG, we may enter into tolling agreements with third parties, including in developing countries, and these counterparties may have greater credit risk than typical. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance. We may not be able to successfully develop, construct and implement our Fast LNG solution, and even if we succeed in developing and constructing the technology, we may ultimately not be able to realize the cost savings and revenues we currently expect to achieve from it, which could result in a material adverse effect upon our operations and business.

We have incurred, and may in the future incur, a significant amount of debt.

On an ongoing basis, we engage with lenders and other financial institutions in an effort to improve our liquidity and capital resources. As of December 31, 2021, we had approximately $3,896 million aggregate principal amount of indebtedness outstanding on a consolidated basis. In connection with the Mergers, we assumed a significant amount of indebtedness, including guarantees and preferred shares, and we incurred a significant amount of debt to pay a portion of the purchase price for the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses, and for general corporate purposes. The terms and conditions of our indebtedness, including some of the indebtedness we assumed as part of the Mergers, include restrictive covenants that may limit our ability to operate our business, to incur or refinance our debt, engage in certain transactions, and require us to maintain certain financial ratios, among others, any of which may limit our ability to finance future operations and capital needs, react to changes in our business and in the economy generally, and to pursue business opportunities and activities.  If we fail to comply with any of these restrictions or are unable to pay our debt service when due, our debt could be accelerated or cross-accelerated, and we cannot assure you that we will have the ability to repay such accelerated debt. Any such default could also have adverse consequences to our status and reporting requirements, reducing our ability to quickly access the capital markets. Our ability to service our existing and any future debt will depend on our performance and operations, which is subject to factors that are beyond our control and compliance with covenants in the agreements governing such debt. We may incur additional debt to fund our business and strategic initiatives.  If we incur additional debt and other obligations, the risks associated with our substantial leverage and the ability to service such debt would increase, which could have a material adverse effect on our business, results of operation and financial condition.

Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms.

We believe we will have sufficient liquidity, cash flow from operations and access to additional capital sources to fund our capital expenditures and working capital needs for the next 12 months. In the future, we expect to incur additional indebtedness to assist us in developing our operations and we are considering alternative financing options, including in specific markets or the opportunistic sale of one of our non-core assets. We also historically have relied, and in the future will likely rely, on borrowings under term loans and other debt instruments to fund our capital expenditures. If any of the lenders in the syndicates backing these debt instruments were unable to perform on its commitments, we may need to seek replacement financing.  We cannot assure you that such additional funding will be available on acceptable terms, or at all. Our ability to raise additional capital on acceptable terms will depend on financial, economic and market conditions, which have increased in volatility and at times have been negatively impacted due to the COVID-19 pandemic, our progress in executing our business strategy and other factors, many of which are beyond our control, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector.  Additional debt financing, if available, may subject us to increased restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resources to service our obligations. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the requirements of our existing financing and availability of such additional funding. If we are unable to obtain additional funding, approvals or amendments to our financings outstanding from time to time, or if additional funding is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan, we may be unable to pay or refinance our indebtedness or to fund our other liquidity needs, and our financial condition or results of operations may be materially adversely affected.

Our current and any future sale and leaseback agreements contain or may contain restrictive covenants that may limit our liquidity and corporate activities.

Hygo’s sale and leaseback agreements for the Nanook, Penguin and Celsius contain, and any future sale and leaseback agreements we may enter into are expected to contain, customary covenants and event of default clauses, including specified financial ratios and financial covenants, including minimum consolidated leverage ratio and the minimum free liquidity covenants, as well as cross-default provisions and restrictive covenants and performance requirements that may affect our operational and financial flexibility. Such restrictions could affect, and in many respects limit or prohibit, among other things, Hygo’s or our ability to incur additional indebtedness, create liens, sell assets, or engage in mergers or acquisitions, as well as our ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities. A failure by Hygo to meet payment and other obligations, including the financial covenant requirements, could lead to defaults under other sale and leaseback agreements or any future sale and leaseback agreements. If we are not in compliance with our covenants and are not able to obtain covenant waivers or modifications, the current or future owners of our leased vessels, as appropriate, could retake possession of the vessels or require us to pay down our indebtedness or sell vessels in our fleet. We could lose our vessels if we default on our bareboat charters in connection with the sale and leaseback agreements, which would negatively affect our revenues, results of operations and financial condition. In addition, Hygo also assigns the shares in its subsidiaries which are the charterers of these vessels to the owners/lessors. There can be no assurance that such restrictions will not adversely affect our ability to finance future operations or capital needs. As a result of these restrictions in current sale and leaseback agreements, or similar restrictions in future sale and leaseback agreements, we may need to seek permission from the owners of our leased vessels to engage in certain corporate actions. Their interests may be different from ours and we may not be able to obtain their permission when needed. This may prevent us from taking actions that we believe are in our best interest, which may adversely impact our revenues, results of operations and financial condition.

We have entered into, and may in the future enter into or modify existing, joint ventures that might restrict our operational and corporate flexibility or require credit support.

We have entered into, and may in the future enter, into joint venture arrangements with third parties in respect of our projects and assets. For example, the Sergipe Facility and Sergipe Power Plant are part of a 50/50 joint venture between Hygo and Ebrasil and our interest in the Hilli is the result of an acquisition by GMLP in July 2018 of 50% of the common units in Hilli LLC (the “Hilli Acquisition”), the disponent owner of Hilli Corp. (as defined herein), the owner of the Hilli, which represents the equivalent of 50% of the two liquefaction trains, out of a total of four, that have been contracted to Perenco Cameroon SA (“Perenco”) and Société Nationale Des Hydrocarbures (“SNH” and, together with Perenco, the “Customer”) pursuant to a Liquefaction Tolling Agreement (“LTA”) with an 8-year term. As we do not operate the assets owned by these joint ventures, our control over their operations is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures. Because we do not control all of the decisions of our joint ventures, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in its or the joint venture’s best interests. For example, we cannot unilaterally cause the distribution of cash by our joint ventures. Additionally, as the joint ventures are separate legal entities, any right we may have to receive assets of any joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the creditors of that joint venture (including tax authorities, trade creditors and any other third parties that require such subordination, such as lenders and other creditors).

Moreover, joint venture arrangements involve various risks and uncertainties, such as our commitment to fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not satisfy their financial obligations to the joint venture. We have provided and may in the future provide guarantees or other forms of credit support to our joint ventures and/or affiliates. For example, in connection with the closing of the Hilli Acquisition, GMLP agreed to provide a several guarantee (the “GMLP Guarantee”) of 50% of the obligations of Hilli Corp, a wholly owned subsidiary of Hilli LLC, under a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Facility”), pursuant to a Deed of Amendment, Restatement and Accession relating to a guarantee between GLNG, Fortune and GMLP dated July 12, 2018. The Hilli Facility provided for post-construction financing for the Hilli in the amount of $960 million.  These guarantees or credit support contain and can contain certain financial restrictions and other covenants that may restrict our business and financing activities. We backstop the GMLP guarantee of Hilli Corp’s debt under the Hiili Leaseback by separately guaranteeing GMLP’s performance. Failure by any of our joint ventures (e.g., Hilli Corp), equity method investees and/or affiliate to service their debt requirements and comply with any provisions contained in their commercial loan agreements, including paying scheduled installments and complying with certain covenants, may lead to an event of default under the related loan agreement. As a result, if our joint ventures, equity method investees and/or affiliates are unable to obtain a waiver or do not have enough cash on hand to repay the outstanding borrowings, the relevant lenders may foreclose their liens on the relevant assets or vessels securing the loans or seek repayment of the loan from us, or both. Either of these possibilities could have a material adverse effect on our business. Further, by virtue of our guarantees with respect to our joint ventures and/or affiliates, this may reduce our ability to gain future credit from certain lenders.

Any use of hedging arrangements may adversely affect our future operating results or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter (“OTC”) options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when expected supply is less than the amount hedged, the counterparty to the hedging contract defaults on its contractual obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

We have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter (“OTC”) options and swaps with other natural gas merchants and financial institutions. Title VII of the Dodd-Frank Act established federal regulation of the OTC derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other federal regulators may adversely affect the cost and availability of the swaps that we may use for hedging, including, without limitation, rules setting limits on the positions in certain contracts, rules regarding aggregation of positions, requirements to clear through specific derivatives clearing organizations and trading platforms, requirements for posting of margins, regulatory requirements on swaps market participants. Our counterparties that are also subject to the capital requirements set out by the Basel Committee on the Banking Supervision in 2011, commonly referred to as “Basel III,” may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets. Our subsidiaries and affiliates operating in Europe and the Caribbean may be subject to the European Market Infrastructure Regulation (“EMIR”) and the Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”) as wholesale energy market participants, which may impose increased regulatory obligations, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data, as well as requiring liquid collateral. These regulations could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, and reduce our ability to monetize or restructure derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to forgo the use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

We may incur impairments to long-lived assets.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, and decline of our market capitalization, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.

Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate.

Weather events such as storms and related storm activity and collateral effects, or other disasters, accidents, catastrophes or similar events, natural or manmade, such as explosions, fires, seismic events, floods or accidents, could result in damage to our Facilities, Liquefaction Facilities, or related infrastructure, interruption of our operations or our supply chain, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our marine and coastal operations. Due to the nature of our operations, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in particular with respect to fleet operations, floating offshore liquefaction units and other infrastructure we may develop in connection with our Fast LNG technology. In particular, we may seek to construct and develop floating offshore liquefaction units as part of our Fast LNG in locations that are subject to risks posed by hurricanes and similar severe weather conditions or natural disasters or other adverse events or conditions that could severely affect our infrastructure, resulting in damage or loss, contamination to the areas, and suspension of our operations.  For example, our our operations in coastal regions in southern Florida, the Caribbean, and Latin America are frequently exposed to natural hazards such as sea-level rise, coastal flooding, cyclones, extreme heat, hurricanes, and earthquakes. These climate risks can affect our operations, potentially even damaging or destroying our facilities, leading to production downgrades, costly delays, reduction in workforce productivity, and potential injury to our people. In addition, jurisdictions with increased political, economic, social and legal instability, lack of regulatory clarity of application of laws, rules and regulations to our technology, and could potentially expose us to additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. In addition, because of the location of some of our operations, we are subject to other natural phenomena, including earthquakes, such as the one that occurred near Puerto Rico in January 2020, which resulted in a temporary delay of development of our Puerto Rico projects. If one or more tankers, pipelines, Facilities, Liquefaction Facilities, vessels, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our Facilities, Liquefaction Facilities, and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe or similar event, our construction projects and our operations could be significantly interrupted, damaged or destroyed. These delays, interruptions and damages could involve substantial damage to people, property or the environment, and repairs could take a significant amount of time, particularly in the event of a major interruption or substantial damage. We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations”. The occurrence of a significant event, or the threat thereof, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Existing and future environmental, social, health and safety laws and regulations could result in increased or more stringent compliance requirements, which may be difficult to comply with or result in additional costs and may otherwise lead to significant liabilities and reputational damage.

Our business is now and will in the future be subject to extensive national, federal, state, municipal and local laws, rules and regulations, in the United States and in the jurisdictions where we operate, relating to the environment, social, health and safety and hazardous substances. These requirements regulate and restrict, among other things: the siting and design of our facilities; discharges to air, land and water, with particular respect to the protection of human health, the environment and natural resources and safety from risks associated with storing, receiving and transporting LNG, natural gas and other substances; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA and the CWA, and analogous laws and regulations in the jurisdictions in which we operate, restrict or prohibit the types, quantities and concentrations of substances that can be emitted into the environment in connection with the construction and operation of our facilities and vessels, and require us to obtain and maintain permits and provide governmental authorities with access to our facilities and vessels for inspection and reports related to our compliance. For example, the Pennsylvania Department of Environmental Protection laws and regulations will apply to the construction and operation of the Pennsylvania Facility. Changes or new environmental, social, health and safety laws and regulations could cause additional expenditures, restrictions and delays in our business and operations, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. For example, in October 2017, the U.S. Government Accountability Office issued a legal determination that a 2013 interagency guidance document was a “rule” subject to the Congressional Review Act (“CRA”). This legal determination could open a broader set of agency guidance documents to potential disapproval and invalidation under the CRA, potentially increasing the likelihood that laws and regulations applicable to our business will become subject to revised interpretations in the future that we cannot predict. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Any failure in environmental, social, health and safety performance from our operations may result in an event that causes personal harm or injury to our employees, other persons, and/or the environment, as well as the imposition of injunctive relief and/or penalties or fines for non-compliance with relevant regulatory requirements or litigation.  Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG liquefaction, storage, transportation or regasification operations), could generate public concern, which may lead to new laws and/or regulations that would impose more stringent requirements on our operations, have a corresponding impact on our ability to obtain permits and approvals, and otherwise jeopardize our reputation or the reputation of our industry as well as our relationships with relevant regulatory agencies and local communities. As the owner and operator of our facilities and vessels, we may be liable, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment at or from our facilities and for any resulting damage to natural resources, which could result in substantial liabilities, fines and penalties, capital expenditures related to cleanup efforts and pollution control equipment, and restrictions or curtailment of our operations. Any such liabilities, fines and penalties that exceed the limits of our insurance coverage. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations”. Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets.

Greenhouse Gases/Climate Change. The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state government levels to monitor and limit existing and future GHG emissions. As a result, our operations are subject to a series of risks associated with the processing, transportation, and use of fossil fuels and emission of GHGs. In the United States to date, no comprehensive climate change legislation has been implemented at the federal level, although various individual states and state coalitions have adopted or considered adopting legislation, regulations or other regulatory initiatives, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and emission restrictions, pollution reduction incentives, or renewable energy or low-carbon replacement fuel quotas. At the international level, the United Nations-sponsored “Paris Agreement” was signed by 197 countries who agreed to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement, effective February 19, 2021, and other countries where we operate or plan to operate, including Jamaica, Brazil, Ireland, Mexico, and Nicaragua, have signed or acceded to this agreement. However, the scope of future climate and GHG emissions-focused regulatory requirements, if any, remain uncertain. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political uncertainty in the United States and worldwide. For example, based in part on the publicized climate plan and pledges by President Biden, there may be significant legislation, rulemaking, or executive orders that seek to address climate change, incentivize low-carbon infrastructure or initiatives, or ban or restrict the exploration and production of fossil fuels. For example, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve U.S. goals under the Paris Agreement.

Climate-related litigation and permitting risks are also increasing, as a number of cities, local governments and private organizations have sought to either bring suit against oil and natural gas companies in state or federal court, alleging various public nuisance claims, or seek to challenge permits required for infrastructure development. Fossil fuel producers are also facing general risks of shifting capital availability due to stockholder concern over climate change and potentially stranded assets in the event of future, comprehensive climate and GHG-related regulation. While several of these cases have been dismissed, there is no guarantee how future lawsuits might be resolved.

The adoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on GHG emissions could result in increased compliance costs, and thereby reduce demand for or erode value for, the natural gas that we process and market. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases in customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHGs, or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. Furthermore, political, litigation, and financial risks may result in reduced natural gas production activities, increased liability for infrastructure damages as a result of climatic changes, or an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Fossil Fuels. Our business activities depend upon a sufficient and reliable supply of natural gas feedstock, and are therefore subject to concerns in certain sectors of the public about the exploration, production and transportation of natural gas and other fossil fuels and the consumption of fossil fuels more generally. For example, PHMSA has promulgated detailed regulations governing LNG facilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. While the Miami Facility is subject to these regulations, none of our LNG facilities currently under development are subject to PHMSA’s jurisdiction, but regulators and governmental agencies in the jurisdictions in which we operate can impose similar siting, design, construction and operational requirements that can affect our projects, facilities, infrastructure and operations. Legislative and regulatory action, and possible litigation, in response to such public concerns may also adversely affect our operations. We may be subject to future laws, regulations, or actions to address such public concern with fossil fuel generation, distribution and combustion, greenhouse gases and the effects of global climate change. Our customers may also move away from using fossil fuels such as LNG for their power generation needs for reputational or perceived risk-related reasons. These matters represent uncertainties in the operation and management of our business, and could have a material adverse effect on our financial position, results of operations and cash flows.

Hydraulic Fracturing. Certain of our suppliers of natural gas and LNG employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations (including shale formations), which currently entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Moreover, hydraulically fractured natural gas wells account for a significant percentage of the natural gas production in the U.S.; the U.S. Energy Information Administration reported in 2016 that hydraulically fractured wells provided two-thirds of U.S. marketed gas production in 2015. Hydraulic fracturing activities can be regulated at the national, federal or local levels, with governmental agencies asserting authority over certain hydraulic fracturing activities and equipment used in the production, transmission and distribution of oil and natural gas, including such oil and natural gas produced via hydraulic fracturing. Such authorities may seek to further regulate or even ban such activities. For example, the Delaware River Basin Commission (“DRBC”), a regional body created via interstate compact responsible for, among other things, water quality protection, water supply allocation, regulatory review, water conservation initiatives, and watershed planning in the Delaware River Basin, has implemented a de facto ban on hydraulic fracturing activities in that basin since 2010 pending the approval of new regulations governing natural gas production activity in the basin. More recently, the DRBC has stated that it will consider new regulations that would ban natural gas production activity, including hydraulic fracturing, in the basin. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).

The requirements for permits or authorizations to conduct these activities vary depending on the location where such drilling and completion activities will be conducted. Several jurisdictions have adopted or considered adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations, or to ban hydraulic fracturing altogether. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and any conditions which may be imposed in connection with the granting of the permit. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction”. Certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In addition, some local jurisdictions have adopted or considered adopting land use restrictions, such as city or municipal ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG and our ability to develop commercially viable LNG facilities.

Indigenous Communities. Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which states that governments are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations, such as are required for our Brazilian operations, are consulted through appropriate procedures and through their representative institutions, particularly using the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for our operations, we are required to comply with the requirements of, consult with, and obtain certain authorizations from a number of institutions regarding the protection of indigenous interests: the National Congress (in specific cases), the Federal Public Prosecutor’s Office and the National Indian Foundation (Fundação Nacional do Índio or FUNAI) (for indigenous people) or Palmares Cultural Foundation (Fundação Cultural Palmares) (for Quilombola communities).

Additionally, the American Convention on Human Rights (“ACHR”), to which Brazil is a party, sets forth rights and freedoms prescribed for all persons, including property rights without discrimination due to race, language, and national or social origin. The ACHR also provides for consultation with indigenous communities regarding activities that may affect the integrity of their land and natural resources. If Brazil’s legal process for consultation and the protection of indigenous rights is challenged under the ACHR and found to be inadequate, it could result in orders or judgments that could ultimately adversely impact its operations. For example, in February 2020, the Interamerican Court of Human Rights (“IACtHR”) found that Argentina had not taken adequate steps, in law or action, to ensure the consulting of indigenous communities and obtaining those communities’ free prior and informed consent for a project impacting their territories. IACtHR further found that Argentina had thus violated the ACHR due to infringements on the indigenous communities’ rights to property, cultural identity, a healthy environment, and adequate food and water by failing to take effective measures to stop harmful, third-party activities on the indigenous communities’ traditional land. As a result, IACtHR ordered Argentina, among other things, to achieve the demarcation and grant of title to the indigenous communities over their territory and the removal of the third-parties from the indigenous territory. We cannot predict whether this decision will result in challenges regarding the adequacy of existing Brazilian legal requirements related to the protection of indigenous rights, changes to the existing Brazilian government body consultation process, or impact our existing development agreements or negotiations for outstanding development agreements with indigenous communities in the areas in which we operate.

There are several indigenous communities that surround our operations in Brazil. Hygo has entered into agreements with some of these communities that mainly provide for the use of their land for our operations, and negotiations with other such communities are ongoing. If we are not able to timely obtain the necessary authorizations or obtain them on favorable terms for our operations in areas where indigenous communities reside, our relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to our operations, we could face construction delays, increased costs, or otherwise experience adverse impacts on its business and results of operations.

International Waters. Our chartered vessels’ operations in international waters and in the territorial waters of other countries are regulated by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vessels operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, the handling and disposal of hazardous substances and wastes and the management of ballast water. The International Maritime Organization (“IMO”) International Convention for the Prevention of Pollution from Ships of 1973, as amended from time to time, and generally referred to as “MARPOL,” can affect operations of our chartered vessels. In addition, our chartered LNG vessels may become subject to the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea (the “HNS Convention”), adopted in 1996 and subsequently amended by a Protocol to the HNS Convention in April 2010. Other regulations include, but are not limited to, the designation of Emission Control Areas under MARPOL, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as amended from time to time, the International Convention on Civil Liability for Bunker Oil Pollution Damage, the IMO International Convention for the Safety of Life at Sea of 1974, as amended from time to time, the International Safety Management Code for the Safe Operations of Ships and for Pollution Prevention, the IMO International Convention on Load Lines of 1966, as amended from time to time and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004.

Moreover, the overall trends are towards more regulations and more stringent requirements which are likely to add to our costs of doing business. For example, IMO regulations, which became applicable on January 1, 2020, limit the sulfur content of fuel oil for ships to 0.5 weight percent starting January 1, 2020, thus increasing the cost of fuel and increasing expenses for us. Likewise, the European Union is considering extending its emissions trading scheme to maritime transport to reduce GHG emissions from vessels. We contract with industry leading vessel providers in the LNG market and look for them to take the lead in maintaining compliance with all such requirements, although the terms of our charter agreements may call for us to bear some or all of the associated costs. While we believe we are similarly situated with respect to other companies that charter vessels, we cannot assure you that these requirements will not have a material effect on our business.

Our chartered vessels operating in U.S. waters, now or in the future, will also be subject to various federal, state and local laws and regulations relating to protection of the environment, including the OPA, the CERCLA, the CWA and the CAA. In some cases, these laws and regulations require governmental permits and authorizations before conducting certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. As with the industry generally, our chartered vessels’ operations will entail risks in these areas, and compliance with these laws and regulations, which may be subject to frequent revisions and reinterpretation, may increase our overall cost of business.

We are subject to numerous governmental export laws, and trade and economic sanctions laws and regulations, and anti-corruption laws and regulation.

We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Latin America, Europe and the other countries in which we seek to do business. We must also comply with trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. For example, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua and in 2018, 2019 and 2020, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the government of Nicaragua and Venezuela. Although we take precautions to comply with all such laws and regulations, violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to, (i) having to suspend our development or operations on a temporary or permanent basis, (ii) being unable to recuperate prior invested time and capital or being subject to lawsuits, or (iii) investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.

We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently, or may in the future, operate may present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Brazil and Mexico or other countries in Latin America, Asia and Africa. Although we have adopted policies and procedures that are designed to ensure that we, our employees and other intermediaries comply with the FCPA, it is highly challenging to adopt policies and procedures that ensure compliance in all respects with the FCPA, particularly in high-risk jurisdictions. Developing and implementing policies and procedures is a complex endeavor. There is no assurance that these policies and procedures will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire.

If we are not in compliance with trade and economic sanctions laws and anti-corruption laws and regulations, including the FCPA, we may be subject to costly and intrusive criminal and civil investigations as well significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and control, the imposition of an independent compliance monitor, as well as potential personnel change and disciplinary actions. In addition, non-compliance with such laws could constitute a breach of certain covenants in operational or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial agreements could trigger an event of default under our other agreements, including our debt agreements. Any adverse finding against us could also negatively affect our relationship and reputation with current and potential customers. In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries. Violations of applicable import, export, trade and economic sanctions, and anti-corruption laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. There can be no assurance that we and our agents and other intermediaries will be in compliance with these provisions in the future. The occurrence of any of these events could have a material adverse impact on our business, results of operations, financial condition, liquidity and future business prospects.  The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time.

Although we believe that we have been in compliance with all applicable sanctions, embargo and anti-corruption laws and regulations, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and conduct our business. In addition, certain financial institutions may have policies against lending or extending credit to companies that have contracts with U.S. embargoed countries or countries identified by the U.S. government as state sponsors of terrorism, which could adversely affect our ability to access funding and liquidity, our financial condition and prospects.

Our Charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business.

None of our vessels have called on ports located in countries subject to comprehensive sanctions and embargoes imposed by the U.S. government or countries identified by the U.S. government as state sponsors of terrorism.  When we charter our vessels to third parties we conduct comprehensive due diligence of the charterer and include prohibitions on the charterer calling on ports in countries subject to comprehensive U.S. sanctions or otherwise engaging in commerce with such countries. However, our vessels may be sub-chartered out to a sanctioned party or call on ports of a sanctioned nation on charterers’ instruction, and without our knowledge or consent.  If our charterers or sub-charterers violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, those violations could in turn negatively affect our reputation and cause us to incur significant costs associated with responding to any investigation into such violations.

Increasing transportation regulations may increase our costs and negatively impact our results of operations.

We are developing a transportation system specifically dedicated to transporting LNG using ISO tank containers and trucks to our customers and Facilities. This transportation system may include trucks that we or our affiliates own and operate. Any such operations would be subject to various trucking safety regulations in the various countries where we operate, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, and transportation of hazardous materials. To a large degree, intrastate motor carrier operations are subject to state and/or local safety regulations that mirror federal regulations but also regulate the weight and size dimensions of loads.  Any trucking operations would be subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include changes in environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size. In addition to increased costs, fines and penalties, any non-compliance or violation of these regulations, could result in the suspension of our operations, which could have a material adverse effect on our business and consolidated results of operations and financial position.

Our chartered vessels operating in certain jurisdictions, including the United States, now or in the future, may be subject to cabotage laws, including the Merchant Marine Act of 1920, as amended (the “Jones Act”).

Certain activities related to our logistics and shipping operations may constitute “coastwise trade” within the meaning of laws and regulations of the U.S. and other jurisdictions in which we operate. Under these laws and regulations, often referred to as cabotage laws, including the Jones Act in the U.S., only vessels meeting specific national ownership and registration requirements or which are subject to an exception or exemption, may engage in such “coastwise trade”. When we operate or charter foreign-flagged vessels, we do so within the current interpretation of such cabotage laws with respect to permitted activities for foreign-flagged vessels. Significant changes in cabotage laws or to the interpretation of such laws in the places where we operate could affect our ability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in those waters. If we do not continue to comply with such laws and regulations, we could incur severe penalties, such as fines or forfeiture of any vessels or their cargo, and any noncompliance or allegations of noncompliance could disrupt our operations in the relevant jurisdiction. Any noncompliance or alleged noncompliance could have a material adverse effect on our reputation, our business, our results of operations and cash flows, and could weaken our financial condition.

We do not own the land on which our projects are located and are subject to leases, rights-of-ways, easements and other property rights for our operations.

We have obtained long-term leases and corresponding rights-of-way agreements and easements with respect to the land on which various of our projects are located, including the Jamaica Facilities, the pipeline connecting the Montego Bay Facility to the Bogue Power Plant (as defined herein), the Miami Facility, the San Juan Facility and the CHP Plant are situated, facilities in Brazil such as the Garuva-Itapoa pipeline connecting the TBG pipeline to the Sao Francisco do Sul terminal, rights of way to the Petrobras/Transpetro OSPAR oil pipeline facilities, among others. In addition, our operations will require agreements with ports proximate to our facilities capable of handling the transload of LNG direct from our occupying vessel to our transportation assets. We do not own the land on which these facilities are located. As a result, we are subject to the possibility of increased costs to retain necessary land use rights as well as applicable law and regulations, including permits and authorizations from governmental agencies or third parties. If we were to lose these rights or be required to relocate, we would not be able to continue our operations at those sites and our business could be materially and adversely affected. For example, our ability to operate the CHP Plant is dependent on our ability to enforce the related lease. General Alumina Jamaica Limited (“GAJ”), one of the lessors, is a subsidiary of Noble Group, which completed a financial restructuring in 2018. If GAJ is involved in a bankruptcy or similar proceeding, such proceeding could negatively impact our ability to enforce the lease. If we are unable to enforce the lease due to the bankruptcy of GAJ or for any other reason, we could be unable to operate the CHP Plant or to execute on our contracts related thereto. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate our assets as anticipated, or at all, which could negatively affect our business, results of operations and financial condition.

We may be adversely affected by the joint investigation by Brazil and the Netherlands into allegations against Hygo’s former Chief Executive Officer, including allegations of improper payments made in Brazil.

On September 23, 2020, Eduardo Antonello, Hygo’s former Chief Executive Officer, was named in a joint corruption investigation in Brazil and the Netherlands. Mauricio Carvalho, the majority shareholder of Evolution Power Partners S.A. (“Evolution”), Hygo’s previous joint venture partner in Centrais Elétricas Barcarena S.A. (“CELBA”), was also named in the investigation. In connection with the investigation, on September 23, 2020, Brazilian federal police executed search warrants on Hygo’s office in Brazil and certain of its joint ventures and seized documents and electronic records and devices belonging to those entities relating to Mr. Antonello, Hygo and its joint ventures. On September 25, 2020, Hygo’s board of directors initiated an internal review with respect to Mr. Antonello’s conduct with respect to Hygo and its joint ventures. The board of directors was assisted in this review by outside counsel and accounting advisors. The review included forensic accounting work, review of certain contracts, interviews with certain company personnel and representatives, and review of internal audit material, certain corporate credit card expenses and Hygo’s anti-corruption policies. The board of directors of Hygo and its advisors did not identify any evidence establishing bribery or other corrupt conduct involving Hygo. In October 2020, before the review was completed, Mr. Antonello resigned as Chief Executive Officer and was replaced by Paul Hanrahan, who also joined the Hygo board of directors. The Hygo board of directors will continue its oversight and review of compliance procedures in accordance with the ethical and corporate governance standards established by applicable law. On April 7, 2021, Evolution transferred 100% of its interest in CELBA to Hygo and its affiliates. While Hygo has conducted its own internal investigation and did not identify evidence establishing bribery or other corrupt conduct involving Hygo, we do not know if any authority is conducting an investigation of Mr. Antonello or Hygo, the results of any investigation, or whether any litigation will arise out of, relating to, or in connection with the investigation or the extent of the impact that the investigation or any such litigation may have on Hygo’s or our businesses. Publicity or other events associating with Mr. Antonello or the investigation, regardless of their foundation or accuracy, could adversely affect Hygo’s and our reputation and our ability to conduct business in Brazil and other jurisdictions.

We could be negatively impacted by environmental, social, and governance (“ESG”) and sustainability-related matters.

Governments, investors, customers, employees and other stakeholders are increasingly focusing on corporate ESG practices and disclosures, and expectations in this area are rapidly evolving. We have announced, and may in the future announce, sustainability-focused goals, initiatives, investments and partnerships. These initiatives, aspirations, targets or objectives reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. Our efforts to accomplish and accurately report on these initiatives and goals present numerous operational, regulatory, reputational, financial, legal, and other risks, any of which could have a material negative impact, including on our reputation and stock price.

In addition, the standards for tracking and reporting on ESG matters are relatively new, have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time and may result in a lack of comparative data from period to period. Moreover, our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting ESG metrics, our interpretation of reporting standards may differ from those of others, and such standards may change over time, any of which could result in significant revisions to our goals or reported progress in achieving such goals. In this regard, the criteria by which our ESG practices and disclosures are assessed may change due to the quickly evolving landscape, which could result in greater expectations of us and cause us to undertake costly initiatives to satisfy such new criteria. The increasing attention to corporate ESG initiatives could also result in increased investigations and litigation or threats thereof. If we are unable to satisfy such new criteria, investors may conclude that our ESG and sustainability practices are inadequate. If we fail or are perceived to have failed to achieve previously announced initiatives or goals or to accurately disclose our progress on such initiatives or goals, our reputation, business, financial condition and results of operations could be adversely impacted.

Information technology failures and cyberattacks could affect us significantly.

We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected. We face various security threats, including cybersecurity threats from third parties and unauthorized users to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our Facilities, Liquefaction Facilities, and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, Facilities, Liquefaction Facilities, and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.

Our current operations and future projects are subject to the inherent risks associated with construction of energy-related infrastructure, LNG, natural gas, power and maritime operations, shipping and transportation of hazardous substances, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, acts of aggression or terrorism, and other risks or hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the Facilities, Liquefaction Facilities and assets or damage to persons and property. We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not generally carry business interruption insurance or political risk insurance with respect to political disruption in the countries in which we operate and that may in the future experience significant political volatility. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses or delays to our development timelines, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Even if we choose to carry insurance for these events in the future, it may not be adequate to protect us from loss, which may include, for example, losses as a result of project delays or losses as a result of business interruption related to a political disruption. Any attempt to recover from loss from political disruption may be time-consuming and expensive, and the outcome may be uncertain. In addition, our insurance may be voidable by the insurers as a result of certain of our actions. Furthermore, we may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult or costly for us to obtain.

Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.

We depend to a large extent on the services of our chief executive officer, Wesley R. Edens, some of our other executive officers and other key employees. Mr. Edens does not have an employment agreement with us. The loss of the services of Mr. Edens or one or more of our other key executives or employees could disrupt our operations and increase our exposure to the other risks described in this Item 1A. Risk Factors. We do not maintain key man insurance on Mr. Edens or any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us.

We are dependent upon the available labor pool of skilled employees for the construction and operation of our Facilities and Liquefaction Facilities, as well as our FSRUs, FLNGs and LNG carriers. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our infrastructure and assets and to provide our customers with the highest quality service. In addition, the tightening of the labor market due to the shortage of skilled employees may affect our ability to hire and retain skilled employees, impair our operations and require us to pay increased wages. We are subject to labor laws in the jurisdictions in which we operate and hire our personnel, which can govern such matters as minimum wage, overtime, union relations, local content requirements and other working conditions. For example, Brazil and Indonesia, where some of our vessels operate, require we hire a certain portion of local personnel to crew our vessels. Any inability to attract and retain qualified local crew members could adversely affect our operations, business, results of operations and financial condition.  Furthermore, should there be an outbreak of COVID-19 on our Facilities or vessels, adequate staffing or crewing may not be available to fulfill the obligations under our contracts. Due to COVID-19, we could face (i) difficulty in finding healthy qualified replacement employees; (ii) local or international transport or quarantine restrictions limiting the ability to transfer infected employees from or to our facilities or vessels, and (iii) restrictions in availability of supplies needed for our projects due to disruptions to third-party suppliers or transportation alternatives. See “—General Risks—We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers”. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations, could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

Our business could be affected adversely by labor disputes, strikes or work stoppages.

Some of our employees, particularly those in our Latin American operations, are represented by a labor union and are covered by collective bargaining agreements pursuant to applicable labor legislation. As a result, we are subject to the risk of labor disputes, strikes, work stoppages and other labor-relations matters. We could experience a disruption of our operations or higher ongoing labor costs, which could have a material adverse effect on our operating results and financial condition. Future negotiations with the unions or other certified bargaining representatives could divert management attention and disrupt operations, which may result in increased operating expenses and lower net income. Moreover, future agreements with unionized and non-unionized employees may be on terms that are note as attractive as our current agreements or comparable to agreements entered into by our competitors. Labor unions could also seek to organize some or all of our non-unionized workforce.

Risks Related to the Jurisdictions in which we Operate

We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.

Our projects are located in Jamaica and the United States (including Puerto Rico), the Caribbean, Brazil, Mexico, Ireland, Nicaragua and other geographies and we have operations and derive revenues from additional markets. Furthermore, part of our strategy consists in seeking to expand our operations to other jurisdictions.  As a result, our projects, operations, business, results of operations, financial condition and prospects are materially dependent upon economic, political, social and other conditions and developments in these jurisdictions. Some of these countries have experienced political, security, and social economic instability in the recent past and may experience instability in the future, including devaluation, depreciation, currency exchange controls, inflation, economic downturns, political instability, social unrest, terrorism, corruption and bribery. For example, in 2019, public demonstrations in Puerto Rico led to the governor’s resignation and the political change interrupted the bidding process for the privatization of PREPA’s transmission and distribution systems. While our operations were not, to date, impacted by the demonstrations or changes in Puerto Rico’s administration, any substantial disruption in our ability to perform our obligations under the Fuel Sale and Purchase Agreement with PREPA could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict how our relationship with PREPA could change given PREPA’s award for its transmission and distribution system. PREPA may seek to find alternative power sources or purchase substantially less natural gas from us than what we currently expect to sell to PREPA. The governments in these jurisdictions differ widely with respect to structure, constitution and stability and some countries lack mature legal and regulatory systems. Governments may seek to impose controls on prices, exchange rates, local and foreign investment and international trade, restrict the ability of companies to dismiss employees, expropriate private sector assets and prohibit the remittance of profits to foreign investors. As our operations depend on governmental approval and regulatory decisions, we may be adversely affected by changes in the political structure or government representatives in each of the countries in which we operate. Any extreme levels of political instability resulting in changes of governments, internal conflict, unrest and violence, especially from terrorist organizations prevalent in the region, could lead to economic disruptions and shutdowns in industrial activities. In addition, these jurisdictions, particularly emerging countries, are subject to risk of contagion from the economic, political and social developments in other emerging countries and markets.

Furthermore, some of the regions in which we operate have been subject to significant levels of terrorist activity and social unrest, particularly in the shipping and maritime industries.  Past political conflicts in certain of these regions have included attacks on vessels, mining of waterways and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. For example, the operations of Hilli Corp in Cameroon, which has experienced instability in its socio-political environment, under the LTA are subject to higher political and security risks than operations in other areas of the world. Tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, Africa or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries. See “—Our Charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business”. We do not, nor do we intend to, maintain insurance (such as business interruption insurance or terrorism) against all of these risks and losses. Any claims covered by insurance will be subject to deductibles, which may be significant, and we may not be fully reimbursed for all the costs related to any losses created by such risks. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations”. As a result, the occurrence of any economic, political, social and other instability or adverse conditions or developments in the jurisdictions in which we operate, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.

While our consolidated financial statements are presented in U.S. dollars, we generate revenues and incur operating expenses and indebtedness in local currencies in the countries where we operate, such as, among others, the euro, the Mexican peso, the Brazilian real and the South African rand. The amount of our revenues denominated in a particular currency in a particular country typically varies from the amount of expenses or indebtedness incurred by our operations in that country given that certain costs may be incurred in a currency different from the local currency of that country, such as the U.S. dollar. Therefore, fluctuations in exchange rates used to translate other currencies into U.S. dollars could result in potential losses and reductions in our margins resulting from currency fluctuations, which may impact our reported consolidated financial condition, results of operations and cash flows from period to period. These fluctuations in exchange rates will also impact the value of our investments and the return on our investments. Additionally, some of the jurisdictions in which we operate may limit our ability to exchange local currency for U.S. dollars and elect to intervene by implementing exchange rate regimes, including sudden devaluations, periodic mini devaluations, exchange controls, dual exchange rate markets and a floating exchange rate system. There can be no assurance that non-U.S. currencies will not be subject to volatility and depreciation or that the current exchange rate policies affecting these currencies will remain the same. For example, the Mexican peso and the Brazilian real have experienced significant fluctuations relative to the U.S. dollar in the past. We may choose not to hedge, or we may not be effective in efforts to hedge, this foreign currency risk. See “—Risks Related to our Business—Any use of hedging arrangements may adversely affect our future operating results or liquidity”. Depreciation or volatility of these currencies against the U.S. dollar could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us and may cause our expenses to increase from time to time relative to our revenues as a result of fluctuations in exchange rates, which could affect the amount of net income that we report in future periods.

Risks Related to Ownership of Our Class A Common Stock

The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders.

The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume in our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above your purchase price, if at all. The market price of our Class A common stock may fluctuate or decline significantly in the future. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our Class A common stock include:


a shift in our investor base;

our quarterly or annual earnings, or those of other comparable companies;

actual or anticipated fluctuations in our operating results;


changes in accounting standards, policies, guidance, interpretations or principles;

announcements by us or our competitors of significant investments, acquisitions or dispositions;

the failure of securities analysts to cover our Class A common stock;

changes in earnings estimates by securities analysts or our ability to meet those estimates;

the operating and share price performance of other comparable companies;

overall market fluctuations;

general economic conditions; and

developments in the markets and market sectors in which we participate.

Stock markets in the United States have experienced extreme price and volume fluctuations. Market fluctuations, as well as general political and economic conditions such as acts of terrorism, prolonged economic uncertainty, a recession or interest rate or currency rate fluctuations, could adversely affect the market price of our Class A common stock. Furthermore, the market price of our common stock may fluctuate significantly following consummation of the Mergers if, among other things, the combined company is unable to achieve the expected growth in earnings, or if the operational cost savings estimates in connection with the integration of our, Hygo’s and GMLP’s businesses are not realized, or if the transaction costs relating to the Mergers are greater than expected, or if the financing relating to the transaction is on unfavorable terms. The market price also may decline if the combined company does not achieve the perceived benefits of the Mergers as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Mergers on the combined company’s financial position, results of operations or cash flows is not consistent with the expectations of financial or industry analysts. In addition, the results of operations of the combined company and the market price of our common stock after the completion of the Mergers may be affected by factors different from those currently affecting the independent results of operations of each of our, Hygo’s and GMLP’s and business.

We are a “controlled company” within the meaning of Nasdaq rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.

Affiliates of certain entities controlled by Wesley R. Edens, Randal A. Nardone and affiliates of Fortress Investment Group LLC (“Founder Entities”) hold a majority of the voting power of our stock. In addition, pursuant to the Shareholders’ Agreement, dated as of February 4, 2019, by and among the Company and the respective parties thereto (the “Shareholders’ Agreement”), the Founder Entities currently have the right to nominate a majority of the members of our Board of Directors. Furthermore, the Shareholders’ Agreement provides that the parties thereto will use their respective reasonable efforts (including voting or causing to be voted all of the Company’s voting shares beneficially owned by each) to cause to be elected to the Board, and to cause to continue to be in office the director nominees selected by the Founder Entities. Affiliates of NFE SMRS Holdings LLC are parties to the Shareholders’ Agreement and as of December 31, 2021 hold approximately 16.0% of the voting power of our stock. As a result, we are a controlled company within the meaning of the Nasdaq corporate governance standards. Under Nasdaq rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:


a majority of the board of directors consist of independent directors as defined under the rules of Nasdaq;

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a controlled company. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation and nominating and governance committees. We intend to utilize some or all of these exemptions. Accordingly, our corporate governance may not afford the same protections as companies that are subject to all of the corporate governance requirements of Nasdaq.

A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders.

As of December 31, 2021, affiliates of the Founder Entities own an aggregate of approximately 112,223,619 shares of Class A common stock, representing 54.3% of our voting power. As of December 31, 2021, Wesley R. Edens, Randal A. Nardone and Fortress Investment Group LLC directly or indirectly own 72,627,776 shares, 26,196,526 shares and 13,399,317 shares, respectively, of our Class A common stock, representing 35.1%, 12.7% and 6.5% of the voting power of the Class A common stock, respectively. The beneficial ownership of greater than 50% of our voting stock means affiliates of the Founder Entities are able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of the affiliates of the Founder Entities with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders, including holders of the Class A common stock.

Given this concentrated ownership, the affiliates of the Founder Entities would have to approve any potential acquisition of us. The existence of a significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the concentration of stock ownership with affiliates of the Founder Entities may adversely affect the trading price of our securities, including our Class A common stock, to the extent investors perceive a disadvantage in owning securities of a company with a significant stockholder.

Furthermore, in connection with the Exchange Transactions (as defined herein), New Fortress Energy Holdings assigned, pursuant to the terms of the Shareholders’ Agreement, to the Founder Entities, New Fortress Energy Holdings’ right to designate a certain number of individuals to be nominated for election to our board of directors so long as its assignees collectively beneficially own at least 5% of the outstanding Class A common stock. The Shareholders’ Agreement provides that the parties to the Shareholders’ Agreement (including certain former members of New Fortress Energy Holdings) shall vote their stock in favor of such nominees. In addition, our Certificate of Incorporation provides the Founder Entities the right to approve certain material transactions so long as the Founder Entities and their affiliates collectively, directly or indirectly, own at least 30% of the outstanding Class A common stock.

Our Certificate of Incorporation and By-Laws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their Class A common stock.

Our Certificate of Incorporation and By-Laws authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of stock constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire us. In addition, some provisions of our Certificate of Incorporation and By-Laws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our securityholders. These provisions include:


dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;

providing that any vacancies may, except as otherwise required by law, or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (provided that vacancies that results from newly created directors requires a quorum);

permitting special meetings of our stockholders to be called only by (i) the chairman of our board of directors, (ii) a majority of our board of directors, or (iii) a committee of our board of directors that has been duly designated by the board of directors and whose powers include the authority to call such meetings;

prohibiting cumulative voting in the election of directors;

establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of the stockholders; and

providing that the board of directors is expressly authorized to adopt, or to alter or repeal our certain provisions of our organizational documents to the extent permitted by law.

Additionally, our Certificate of Incorporation provides that we have opted out of Section 203 of the Delaware General Corporation Law. However, our Certificate of Incorporation includes a similar provision, which, subject to certain exceptions, prohibits us from engaging in a business combination with an “interested stockholder,” unless the business combination is approved in a prescribed manner. Subject to certain exceptions, an “interested stockholder” means any person who, together with that person’s affiliates and associates, owns 15% or more of our outstanding voting stock or an affiliate or associate of ours who owned 15% or more of our outstanding voting stock at any time within the previous three years, but shall not include any person who acquired such stock from the Founder Entities or NFE SMRS Holdings LLC (except in the context of a public offering) or any person whose ownership of stock in excess of 15% of our outstanding voting stock is the result of any action taken solely by us. Our Certificate of Incorporation provides that the Founder Entities and NFE SMRS Holdings LLC and any of their respective direct or indirect transferees, and any group as to which such persons are a party, do not constitute “interested stockholders” for purposes of this provision.

Our By-Laws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our By-Laws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is, to the fullest extent permitted by applicable law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers or employees arising pursuant to any provision of our organizational documents or the Delaware Limited Liability Company Act (“DGCL”), or (iv) any action asserting a claim against us or any of our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in our stock will be deemed to have notice of, and consented to, the provisions described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it considers more likely to be favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our organizational documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, results of operations or prospects.

The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all.

The declaration and payment of dividends to holders of our Class A common stock will be at the discretion of our board of directors in accordance with applicable law after taking into account various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deem relevant. There can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all. Because we are a holding company and have no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries and our ability to receive distributions from our subsidiaries may be limited by the financing agreements to which they are subject.

The incurrence or issuance of debt which ranks senior to our Class A common stock upon our liquidation, including any debt issued in connection with the financing of the Mergers and future issuances of equity or equity-related securities, which would dilute the holdings of our existing Class A common stockholders and may be senior to our Class A common stock for the purposes of making distributions, periodically or upon liquidation, may negatively affect the market price of our Class A common stock.

We have incurred and may in the future incur or issue debt, including any debt issued in connection with the financing of the Mergers, or issue equity or equity-related securities to finance our operations, acquisitions or investments. Upon our liquidation, lenders and holders of our debt and holders of our preferred stock (if any) would receive a distribution of our available assets before Class A common stockholders. Any future incurrence or issuance of debt would increase our interest cost and could adversely affect our results of operations and cash flows. We are not required to offer any additional equity securities to existing Class A common stockholders on a preemptive basis. Therefore, additional issuances of Class A common stock, directly or through convertible or exchangeable securities (including limited partnership interests in our operating partnership), warrants or options, will dilute the holdings of our existing Class A common stockholders and such issuances, or the perception of such issuances, may reduce the market price of our Class A common stock. Any preferred stock issued by us would likely have a preference on distribution payments, periodically or upon liquidation, which could eliminate or otherwise limit our ability to make distributions to Class A common stockholders. Because our decision to incur or issue debt or issue equity or equity-related securities in the future will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. Thus, Class A common stockholders bear the risk that our future incurrence or issuance of debt or issuance of equity or equity-related securities will adversely affect the market price of our Class A common stock.

We may issue preferred stock, the terms of which could adversely affect the voting power or value of our Class A common stock.

Our Certificate of Incorporation and By-Laws authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock in respect of dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

Sales or issuances of our Class A common stock could adversely affect the market price of our Class A common stock.

Sales of substantial amounts of our Class A common stock in the public market, or the perception that such sales might occur, could adversely affect the market price of our Class A common stock. The issuance of our Class A common stock in connection with property, portfolio or business acquisitions or the exercise of outstanding options or otherwise could also have an adverse effect on the market price of our Class A common stock.

An active, liquid and orderly trading market for our Class A common stock may not be maintained and the price of our Class A common stock may fluctuate significantly.

Prior to January 2019, there was no public market for our Class A common stock. An active, liquid and orderly trading market for our Class A common stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock.

General Risks

We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest.

We conduct our business mainly through our operating subsidiaries and affiliates, including joint ventures and other special purpose entities, which are created specifically to participate in projects or manage a specific asset. Our ability to meet our financial obligations is therefore related in part to the cash flow and earnings of our subsidiaries and affiliates and the ability or willingness of these entities to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments, which are governed by various shareholder agreements, joint venture financing and operating arrangements. In addition, some of our operating subsidiaries, joint venture and special purpose entities are subject to restrictive covenants related to their indebtedness, including restrictions on dividend distributions. Any additional debt or other financing could include similar restrictions, which would limit their ability to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments. Similarly, we may fail to realize anticipated benefits of any joint venture or similar arrangement, which could adversely affect our financial condition and results of operation.

We may engage in mergers, sales and acquisitions, divestments, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value.

In furtherance of our business strategy, we may engage in mergers, purchases or sales, divestments, reorganizations or other similar transactions related to our businesses or assets in the future. Any such transactions may be subject to significant risks and contingencies, including the risk of integration, valuation and successful implementation, and we may not be able to realize the benefits of any such transactions. We may also engage in sales of our assets or sale and leaseback transactions that seek to monetize our assets and there is no guarantee that such sales of assets will be executed at the prices we desire or higher than the values we currently carry these assets at on our balance sheet.  We do not know if we will be able to successfully complete any such transactions or whether we will be able to retain key personnel, suppliers or distributors. Our ability to successfully implement our strategy through such transactions depends upon our ability to identify, negotiate and complete suitable transactions and to obtain the required financing on terms acceptable to us. These efforts could be expensive and time consuming, disrupt our ongoing business and distract management. If we are unable to successfully complete our transactions, our business, financial condition, results of operations and prospects could be materially adversely affected.

We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.

The COVID-19 pandemic has caused, and is expected to continue to cause, economic disruptions in various regions, disruptions in global supply chains, significant volatility and disruption of financial markets and in the price of oil and other commodities. In addition, the pandemic has made travel and commercial activity significantly more cumbersome and less efficient compared to pre-pandemic conditions. Because the severity, magnitude and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly-changing and difficult to predict, the pandemic’s impact on our operations and financial performance, as well as its impact on our ability to successfully execute our business strategies and initiatives, remains uncertain and difficult to predict. Further, the ultimate impact of the COVID-19 pandemic on our operations and financial performance depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that have been and continue to be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures); the impact of the pandemic and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs, as well as other monetary and financial policies enacted by governments (including monetary policy, taxation, exchange controls, interest rates, regulation of banking and financial services and other industries, government budgeting and public sector financing); general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery when the COVID-19 pandemic subsides. The COVID-19 pandemic has subjected our operations, financial performance and financial condition to a number of operational financial risks. Although the services we provide are generally deemed essential, we may face negative impacts from increased operational challenges based on the need to protect employee health and safety, workplace disruptions and restrictions on the movement of people including our employees and subcontractors, and disruptions to supply chains related to raw materials and goods both at our own Facilities, Liquefaction Facilities and at customers and suppliers. We may also experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the pandemic’s impact on the operations and financial condition of our customers and potential customers, as well as the price of available fuel options, including oil-based fuels as well as strains the pandemic places on the capacity of potential customers to evaluate purchasing our goods and services. We may experience customer requests for potential payment deferrals or other contract modifications and delays of potential or ongoing construction projects due to government guidance or customer requests. Conditions in the financial and credit markets may limit the availability of funding and pose heightened risks to future financings we may require. These and other factors we cannot anticipate could adversely affect our business, financial position and results of operations. It is possible that the longer this period of economic and global supply chain and disruption continues, the greater the uncertainty will be regarding the possible adverse impact on our business operations, financial performance and results of operations.

A change in tax laws in any country in which we operate could adversely affect us.

Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing laws, treaties and regulations in and between the countries in which we operate. Our tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, regulations, or treaties, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing businesses and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect.

We are and may be involved in legal proceedings and may experience unfavorable outcomes.

We are and may in the future be subject to material legal proceedings in the course of our business or otherwise, including, but not limited to, actions relating to contract disputes, business practices, intellectual property, real estate and leases, and other commercial, tax, regulatory and permitting matters. Such legal proceedings may involve claims for substantial amounts of money or for other relief or might necessitate changes to our business or operations, and the defense of such actions may be both time-consuming and expensive. Moreover, the process of litigating requires substantial time, which may distract our management. Even if we are successful, any litigation may be costly, and may approximate the cost of damages sought. These actions could also expose us to adverse publicity, which might adversely affect our reputation and therefore, our results of operations. Further, if any such proceedings were to result in an unfavorable outcome, it could have an adverse effect on our business, financial position and results of operations.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with stock listed on Nasdaq, we are subject to an extensive body of regulations, including certain provisions of the Sarbanes-Oxley Act, the Dodd-Frank Act, regulations of the SEC and Nasdaq requirements. Compliance with these rules and regulations increases our legal, accounting, compliance and other expenses. For example, as a result of becoming a public company, we added independent directors and created additional board committees. We entered into an administrative services agreement with FIG LLC, an affiliate of Fortress Investment Group (which currently employs Messrs. Edens, our chief executive officer and chairman of our Board of Directors, and Nardone, one of our Directors), in connection with the IPO, pursuant to which FIG LLC provides us with certain back-office services and charges us for selling, general and administrative expenses incurred to provide these services. In addition, we may incur additional costs associated with our public company reporting requirements and maintaining directors’ and officers’ liability insurance. It is possible that our actual incremental costs of being a publicly traded company will be higher than we currently estimate, and the incremental costs may have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our share price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose viability in the financial markets, which in turn could cause our share price or trading volume to decline.

Item 1B.
Unresolved Staff Comments.

None.

Item 3.
Legal Proceedings.

We are not currently a party to any material legal proceedings. In the ordinary course of business, various legal and regulatory claims and proceedings may be pending or threatened against us. If we become a party to proceedings in the future, we may be unable to predict with certainty the ultimate outcome of such claims and proceedings.

Item 4.
Mine Safety Disclosures.

Not applicable.

PART II

Item 5.
Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “NFE.” On February February 24, 2022, there were 17 holders of record of our Class A common stock. This number does not include shareholders whose shares are held for them in “street name” meaning that such shares are held for their accounts by a broker or other nominee. The actual number of beneficial shareholders is greater than the number of holders of record.

Dividends

We declared dividends of $0.10 per share in March, June, September and December totaling $79,834 in dividend payments during the year ended December 31, 2021. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our board of directors may deem relevant.

Securities Authorized for Issuance Under Equity Compensation Plans

The information required by this Item is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with our 2022 annual meeting of shareholders and is incorporated herein by reference.

Share Performance Graph

The following graph compares the cumulative total return to shareholders on our Class A common stock relative to the S&P 500, iShares Global Clean Energy ETF Index (“ICLN”) and Vanguard Energy ETF (“VDE”), including reinvestment of dividends. The graph assumes that on January 31, 2019, the date our Class A shares began trading on the NASDAQ, $100 was invested in our Class A shares and in each index based on the closing market price, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.

The following Performance Graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such filing.

graphic

Cumulative Total Return Percentage
Company / Index
January 31, 2019(1)
December 2019(2)
December 2020(2)
December 2021(2)
NFE
100.0%
19.9%
312.4%
88.0%
S&P 500
100.0%
19.5%
38.9%
76.3%
iShares Global Clean Energy ETF Index (“ICLN”)
100.0%
25.6%
203.8%
130.3%
Vanguard Energy ETF (“VDE”)
100.0%
-2.2%
-34.5%
2.3%
(1)
Date of the IPO
(2)
Last trading day of the month

Use of Proceeds from Registered Securities

On February 4, 2019, we completed the IPO of 20,000,000 Class A shares pursuant to our registration statement on Form S-1 (File No. 333-228339) (the “Registration Statement”) declared effective by the SEC on January 30, 2019. In connection with the IPO, Morgan Stanley & Co. LLC, Barclays Capital Inc., Citigroup Global Markets Inc. and Credit Suisse Securities (USA) LLC acted as representatives of the underwriters; Evercore Group L.L.C. and Allen & Company LLC acted as joint book-running managers; and JMP Securities LLC and Stifel, Nicolaus & Company Incorporated acted as co-managers. The gross proceeds of the IPO, based on a public offering price of $14.00 per Class A share, were $280.0 million, which resulted in net proceeds to us of $257.0 million, after deducting underwriting discounts and commissions and transaction costs. In addition, on March 1, 2019, the underwriters exercised their option to purchase an additional 837,272 Class A shares at the initial offering price of $14.00 per share, less underwriting discounts, which resulted in $11.0 million in additional net proceeds after deducting underwriting discounts and commissions, such that there were 20,837,272 outstanding Class A shares. We contributed the net proceeds of the IPO to NFI in exchange for NFI’s issuance to us of 20,837,272 NFI LLC Units. NFI used the net proceeds in connection with the construction of our Facilities, as well as for working capital and general corporate purposes, including the development of future projects. No fees or expenses were paid, directly or indirectly, to any officer, director, 10% unitholder or other affiliate.

In December 2020, NFE issued 5,882,352 shares of Class A common stock and received proceeds of $290.8 million, net of $1.2 million in issuance costs. These proceeds were used for general corporate purposes.

Item 6.
Reserved.

Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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 10‑K 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”.

On April 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 in Sergipe, Brazil (the “Sergipe Power Plant”) and its operating FSRU terminal in Sergipe, 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 in Brazil, Indonesia, Jamaica and Jordan 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.

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 in Miami, 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 in Jamaica, Puerto Rico, Mexico and Brazil, 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 in Hilli 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 in Jamaica and Puerto Rico, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, and the Puerto Rico Electric Power Authority (“PREPA”), each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers.

We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our Miami Facility. Our long-term goal is to develop the infrastructure necessary to supply our existing and future customers with LNG produced primarily at our own facilities, including Fast LNG and our expanded delivery logistics chain in Northern 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 of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue Power Plant in Montego Bay, Jamaica. Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 740,000 gallons of LNG (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.

Old Harbour Facility

The Old Harbour Facility 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 in June 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 in Clarendon, Jamaica (the “CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term PPA. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay SSA. In March 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. In August 2020, we began to deliver gas to Jamalco to utilize in their gas-fired boilers.

San Juan Facility

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 the Port 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 in Puerto Rico. We have delivered natural gas to PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 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.

We also own expansion rights with respect to the Sergipe Power Plant, which are owned by Centrais Elétricas Barra 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 in April 2016. This facility has liquefaction capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.

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 in Hilli LLC, owner and operator of the Hilli, is also included in the Ships segment. Hilli Corp, a wholly owned subsidiary of Hilli LLC, has a Liquefication Tolling Agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures under which the Hilli provides liquefaction services through July 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

In July 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). Initially, we are supplying CFEnergia with natural gas to power plants located in Punta 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. The La 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 “La Paz Power Plant”) following the start of operations. Natural gas supply to the La Paz 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, in Puerto 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 with Nicaragua’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 in Pará, 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.

Santa Catarina Facility

The Santa Catarina Facility will be located on the southern coast of Brazil 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 inland Transportadora 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 the State 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 the State 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 the Port of Suape, in the city of Ipojuca, State of Pernambuco, Brazil, pursuant to the purchase of CH4 Energia Ltda. on January 12, 2021. We own certain 15-year power purchase agreements totaling 288MW for the development of two thermoelectric power plants, in the State of Bahia, Brazil, following the acquisition of 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energética Camaçari Muricy II S.A. (“Muricy”) on March 11, 2021. As of January 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 in Brazil 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 the Port of Suape, to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil.

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 La Paz Power Plant, the Nicaragua 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”) in Ireland 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 Developments

Cargo Sales

Since August 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 ended December 31, 2021.

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

On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which is September 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 the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19 and July 15 orders with the United States Court of the Appeals for the District of Columbia Circuit. To date, no other party has sought review of FERC’s orders. While our petitions for review are pending, and in order to comply with the FERC’s directive, on September 15, 2021 we filed an application for authorization to operate the San Juan Facility, which remains pending.

Results of Operations – Year Ended December 31, 2021 compared to Year Ended December 31, 2020 (in thousands)

Segment performance is evaluated based on segment operating margin and the tables below presents our segment information for the years ended December 31, 2021 and 2020:

Year Ended December 31, 2021
 
(in thousands of $)
 
Terminals and
Infrastructure⁽¹⁾
   
Ships⁽²⁾
   
Total Segment
   
Consolidation
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 ended December 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 ended December 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 ended December 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.

The following tables summarize the volumes delivered in the year ended December 31, 2021 as compared to the year ended December 31, 2020:

   
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
     
1.2
 
Total volumes delivered in the current period
   
41.8
     
35.6
     
6.2
 

The Old Harbour Facility sold additional volumes in the year ended December 31, 2021 as compared to the year ended December 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 $46,307 from $189,196 for the year ended December 31, 2020 to $235,503 for the year ended December 31, 2021. 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 December 31, 2020 and an increase in volumes delivered at the Old Harbour Power Plant.


Revenue from the delivery of power and steam increased by $5,833 from $23,415 for the year ended December 31, 2020 to $29,248 for the year ended December 31, 2021, which began during March 2020 under our contracts with JPS and Jamalco.


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 August 2021, and no gas volumes have 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 $4,067 from $93,236 for the year ended December 31, 2020 to $97,303 for the year ended December 31, 2021. The increase in revenue from the Montego Bay Facility was due to an increase in the Henry Hub index used to invoice our customers compared to the year ended December 31, 2020 and increased volume sold to industrial end users. Additional 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 Port of Montego Bay 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 ended December 31, 2020 to $191,674 for the year ended December 31, 2021. The increase was driven by additional volumes consumed at the San Juan Power Plant, increasing by 54.5 million gallons (4.2 TBtu), as our San Juan Facility was not completed until July 2020.

Revenue from cargo sales was $462,695 for the year ended December 31, 2021; there were no comparable transactions in the year ended December 31, 2020.

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 ended December 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 in Brazil. 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.

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 our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales.

Cost of sales increased $510,302 for the year ended December 31, 2021 as compared to the year ended December 31, 2020.


Cost of LNG purchased from third parties for sale to our customers increased $117,943 for the year ended December 31, 2021 as compared to the year ended December 31, 2020. The increase was primarily attributable to a 16% increase in volumes delivered compared to the year ended December 31, 2020 and an increase in LNG cost. The weighted-average cost of LNG purchased from third parties increased from $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020 to $0.59 per gallon ($7.09 per MMBtu) for the year ended December 31, 2021.


Cost of LNG from the sale of cargos in the market was $191,308 for the year ended December 31, 2021 as compared to $0 for the year ended December 31, 2020. 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 $175,847 for the year ended December 31, 2021, which was comprised of LNG costs to fuel the 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 December 31, 2021 and December 31, 2020 was $0.80 per gallon ($9.71 per MMBtu) and $0.40 per gallon ($4.81 per MMBtu), respectively.

Charter costs increased Cost of sales by $7,633 for the year ended December 31, 2021 as compared to the year ended December 31, 2020. The increase was attributable to an additional vessel in our fleet associated with our San Juan Facility after our assets were placed in service in the third quarter of 2020, as well as 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 ended December 31, 2021 as compared to the year ended December 31, 2020.


The increase for the year ended December 31, 2021 as compared to the year ended December 31, 2020 was also the result of San Juan Facility and the CHP Facility during the year ended December 31, 2021 that were still in development during a portion of the year ended December 31, 2020. Operations and maintenance 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 $19,108 for the year ended December 31, 2021, which was primarily comprised of costs related to the operation and services agreement for the Nanook, insurance costs and costs for connecting to the transmission system.

Ships Segment

 
(in thousands of $)
 
Year Ended
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 ended December 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 ended December 31, 2021 represents eight and a half months of operations of each of the acquired vessels.

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 ended December 31, 2021, as compared to the year ended December 31, 2020. The increase was primarily attributable to $33,059 of higher payroll costs associated with increased headcount for the year ended December 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 ended December 31, 2021, we incurred $44,671 for transaction and integration costs, as compared to $4,028 for the year ended December 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 December 31, 2020, we incurred $4,028 of third-party fees associated with a new credit agreement that was accounted for as a modification.

Contract termination charges and loss on mitigation sales

Loss on mitigation sales for the year ended December 31, 2020 was $124,114. In June 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 in Jamaica. 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 ended December 31, 2021.

Depreciation and amortization

Depreciation and amortization increased $66,001 for the year ended December 31, 2021 as compared to the year ended December 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 $38,950 of incremental depreciation expense for the acquired vessels during the year ended December 31, 2021;


Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $16,658 for the year ended December 31, 2021;


Increase in depreciation of $5,179 for the San Juan Facility that went into service in July 2020 for the year ended December 31, 2021; and


Increase in depreciation of $2,536 for the CHP Plant that went into service in March 2020 for the year ended December 31, 2021.

Interest expense

Interest expense increased by $88,601 for the year ended December 31, 2021 as compared to the year ended December 31, 2020. The increase was primarily due to an increase in total principal outstanding due to the issuance of the 2025 Notes in September 2020, the 2026 Notes in April 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 of December 31, 2021 as compared to total outstanding debt of $1,250,000 as of December 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 ended December 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 $22,155 for the year ended December 31, 2021, respectively, as compared to the year ended December 31, 2020. Other (income), net of $17,150 primarily consisted of:


Gains in investments in equity securities of $8,254 for the year ended December 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 ended December 31, 2021.

Loss on extinguishment of debt, net

Loss on extinguishment of debt for the year ended December 31, 2021 was $10,975. In November 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.

Loss on extinguishment of debt for the year ended December 31, 2020 was $33,062 as a result of the extinguishment of previous credit facilities in January 2020 and September 2020.

Tax provision

We recognized a tax provision for the year ended December 31, 2021 of $12,461 compared to a tax provision of $4,817 for the year ended December 31, 2020. The increase to the tax provision and effective tax rate for the year ended December 31, 2021 was primarily driven by an increase in pre-tax income in certain profitable foreign operations, primarily in Jamaica. We also acquired profitable vessel operations in the United Kingdom in the Mergers. For the year ended December 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 ended December 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 ended December 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 ended December 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 April 2021. Upon completion of 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 April 15, 2021. Our results of operations in 2021 also include transaction and 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 December 31, 2021 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami 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 Mexico. We are continuing to develop of our La Paz 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 December 31, 2021. During 2020 and 2021, we entered into LNG supply agreements for the purchase of approximately 601 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement. We 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.

Since August 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.

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 January 2020, we borrowed $800,000 under a credit agreement, and repaid our prior term loan facility in full.


In September 2020, we issued $1,000,000 of 2025 Notes and repaid all other outstanding debt. No principal payments are due on the 2025 Notes until maturity in 2025.


In December 2020, we received proceeds of $263,125 from the issuance of $250,000 of additional notes on the same terms as the 2025 Notes (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein).


In December 2020, we issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs.


In April 2021, we issued $1,500,000 of 2026 Notes; we also entered into the $200,000 Revolving Facility that has a term of approximately five years.


In August 2021, we entered into the CHP Facility (defined below) and initially drew $100,000, which may be increased to $285,000.


In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility (defined below). Under this facility, we 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.

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 through December 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 the South Power 2029 Bonds (defined below). We may also enter into other financing arrangements to generate proceeds to fund our developments. Through December 31, 2021, we have spent approximately $128 million to develop the Pennsylvania 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 December 31, 2021:

(in thousands)
 
Total
   
Year 1
   
Years 2 to 3
   
Years 4 to 5
   
More than 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
 

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 of December 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 as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of December 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 of December 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 New York, as well as offices in Miami, New Orleans, and Rio de Janeiro, which have lease terms between three to seven years.

Cash Flows

The following table summarizes the changes to our cash flows for the year ended December 31, 2021 and 2020, respectively:

   
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
)

Cash provided by (used in) operating activities

Our cash flow provided by operating activities was $84,770 for the year ended December 31, 2021, which increased by $210,336 from cash used in operating activities of $125,566 for the year ended December 31, 2020. Our net income for the year ended December 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 ended December 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 after December 31, 2021.

Cash used in investing activities

Our cash flow used in investing activities was $2,273,561 for the year ended December 31, 2021, which increased by $2,115,930 from cash used in investing activities of $157,631 for the year ended December 31, 2020. Cash used for the Mergers, net of cash acquired was $1,586,042. Cash outflows for investing activities during the year ended December 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 ended December 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 ended December 31, 2020.

Cash provided by financing activities

Our cash flow provided by financing activities was $1,816,944 for the year ended December 31, 2021, which increased by $997,446 from cash provided by financing activities of $819,498 for the year ended December 31, 2020. Cash provided by financing activities during the year ended December 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 ended December 31, 2021.

Cash flow provided by financing activities during the year ended December 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 in Jamaica 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 in Jamaica of $183,600, and our previous term loan facility of $506,402.

Long-Term Debt and Preferred Stock

2025 Notes

In September 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 on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 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.

In December 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 of December 31, 2021 and December 31, 2020, remaining unamortized deferred financing costs for the 2025 Notes was $8,804 and $10,439, respectively.

2026 Notes

In April 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 on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 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 of December 31, 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $22,488.

Vessel Term Loan Facility

In September 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 in September 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 that GMLP 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 Consolidated Net Worth is greater than $250,000, each as defined in the Vessel Term Loan Facility.  The Company was in compliance with these covenants as of December 31, 2021.

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 of December 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 of BRL 255,600 (approximately $45,000) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil 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 on September 13 and March 13.

The Debenture Loan is fully and unconditionally guaranteed by 100% of the shares issued by NFE Brasil owned by our consolidated subsidiary, LNG Power Ltd.

CHP Facility

In August 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 of December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $3,180.

Subsequent to December 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 in South 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 the South Power 2029 Bonds. In February 2022, $59,730 was funded under the South 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 in May 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

In April 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 ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 (each as defined in the Revolving Facility).  The Company was in compliance with these covenants as of December 31, 2021.

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 of December 31, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $3,807. As of December 31, 2021, the full capacity of the Revolving Facility has been drawn and $200,000 remains outstanding.

Subsequent to December 31, 2021, on February 28, 2022, we entered into an amendment to the Revolving Facility to increase the commitment thereunder by up to $200,000.

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 with Compass Shipping 23 Corporation 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 23 Corporation Limited, the owner of the Nanook, has a long-term loan facility that is denominated in USD, which matures in September 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 in December 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 with Noble 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.

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 in May 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 in March 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 23 Leasing Co. Limited of China Merchants Bank Leasing (the “Eskimo Leaseback”). Sea 23 Leasing 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.

In November 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 ended December 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 after October 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 in CELSEPAR 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 of December 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 in April 2032.

Credit facility (Real and USD in millions)
 
Principal Outstanding
 
Effective Interest
Rate (1)
IFC
 
 R$
 899.4($160.3)
 
IPCA + 9.69%
Inter-American Development Bank
 
 R$
 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) The IFC and Inter-American Development Bank facilities are Real-denominated and indexed to the Índice Nacional de Preços ao Consumidor Amplo (“IPCA”).

CELSE also issued debentures in the aggregate principal amount of R$3,370.0 million (net proceeds of $897.2 million as of the issuance date), due April 2032, bearing interest at a fixed rate of 9.85% (the “CELSE Debentures”). As of December 31, 2021, the principal balance of the CELSE Debentures was R$3,113 million ($554.7 million as of December 31, 2021). Interest is payable on the CELSE Debentures semi-annually on each April 15 and October 15, beginning on October 15, 2018. The CELSE Debentures are amortized and repaid in 24 consecutive semi-annual installments on each of April 15 and October 15, that commenced on October 15, 2020.

The indenture governing the CELSE Debentures contains covenants that: (i) requires CELSE to maintain a historical debt service coverage ratio for a twelve month period on or after March 31, 2021 of no less than 1.10 to 1.00; (ii) prohibit certain restricted payments; (iii) limit the ability of CELSE from creating any liens or incurring additional indebtedness; (iv) prohibit certain fundamental changes; (v) limit the ability of CELSE to transfer or purchase assets; (vi) prohibit certain affiliate transactions; (vii) limit the ability of CELSE to make change orders or give other directions under the documents related to the construction and operation of the project in certain circumstances; (viii) limit the ability of CELSE to enter into additional contracts; (ix) limit CELSE’s operating expenses and capital expenditures; and (x) prohibit CELSE from transferring, purchasing or otherwise acquiring any portion of the CELSE Debentures, other than pursuant to the exercise of the put option.

In July 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 with GE 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 on May 30 and November 30 each year, beginning on May 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 on November 30, 2024.  The GE Credit Facility includes covenants and events of default that are customary for similar transactions.

In July 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 of December 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 do Brasil S.A.—Ebrasil.

Golar Hilli Leaseback

As part of the Mergers, we acquired an investment in Hilli LLC; Golar Hilli Corporation (“Hilli Corp”), is a direct subsidiary of Hilli LLC and is a party to a Memorandum of Agreement with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). 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 of Hilli Corp’s indebtedness of $729 million amounted to $364.5 million as of December 31, 2021.

As part of the Mergers, we have assumed a guarantee of 50% of the outstanding principal and interest amounts payable by Hilli 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 of Hilli 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

In July 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.

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.

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.

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 the Cool 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 the Cool 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.

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.

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 December 31, 2021.

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.

Item 7A.
Quantitative and Qualitative Disclosures About Market Risks.

In the normal course of business, the Company encounters several significant types of market risks including commodity and interest rate risks.

Commodity Price Risk

Commodity price risk is the risk of loss arising from adverse changes in market rates and prices. We are able to limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a contractual spread. Our exposure to market risk associated with LNG price changes may adversely impact our business. We do not currently have any derivative arrangements to protect against fluctuations in commodity prices, but to mitigate the effect of fluctuations in LNG prices on our operations, we may enter into various derivative instruments.

Interest Rate Risk

The 2025 Notes and 2026 Notes were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the 2025 Notes and 2026 Notes but such a change would have no impact on our results of operations or cash flows. A 100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $102 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve.

Interest under the Vessel Term Loan Facility has a component based on LIBOR or other market indices should LIBOR become unavailable. A 100-basis point increase or decrease in the market interest rate would decrease or increase our interest expense by approximately $4,300.

As a result of the Mergers, we assumed the Debenture Loan and a cross-currency interest rate swap to protect against adverse movements in interest rates of the Debenture Loan. We also acquired an interest rate swap to manage the exposure to adverse movements in interest rates of debt held by our equity method investee, Hilli LLC, but we do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our other outstanding indebtedness.

Foreign Currency Exchange Risk

After the completion of the Hygo Merger, we began to have more significant transactions, assets and liabilities denominated in Brazilian reais; our Brazilian subsidiaries and investments receive income and pays expenses in Brazilian reais. A portion of our exposure to exchange rates is economically hedged by a cross-currency interest rate swap. Based on our Brazilian reais revenues and expenses for the period since the completion of the Hygo Merger, a 10% depreciation of the U.S. dollar against the Brazilian reais would not significantly decrease our revenue or expenses. As our operations expand in Brazil, our results of operations will be exposed to changes in fluctuations in the Brazilian real, which may materially impact our results of operations.

Outside of Brazil, our operations are primarily conducted in U.S. dollars, and as such, our results of operations and cash flows have not materially been impacted by fluctuations due to changes in foreign currency exchange rates. We currently incur a limited amount of costs in foreign jurisdictions other than Brazil that are paid in local currencies, but we expect our international operations to continue to grow in the near term.

Item 8.
Financial Statements and Supplementary Data.

Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this Annual Report and are incorporated herein by reference.

Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A.
Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2021. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2021 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

As previously noted in this Form 10-K, we completed the acquisition of Hygo and GMLP on April 15, 2021. As permitted by related SEC staff interpretative guidance for newly acquired businesses, Hygo and GMLP have been excluded from management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, except for the recognition of goodwill and intangible assets that were included in management’s assessment. Hygo and GMLP are included in the 2021 consolidated financial statements of the Company and constituted approximately 31% and 22% of the Company’s total assets, respectively, as of December 31, 2021 after excluding goodwill and intangible assets and approximately 5% and 14% of the Company’s revenues, respectively, for the year then ended. See Part II, Item 8, Note 4, “Notes to Consolidated Financial Statements”, contained in this Form 10-K for further description of the significance of the acquired businesses to us.

As of December 31, 2021, our management assessed the effectiveness of our internal control over financial reporting based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control – Integrated Framework (2013).” Based on this assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2021.

The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by EY, an independent registered public accounting firm, as stated in their report, which appears herein.

Item 9B.
Other Information.

None.

Item 9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

None.

Part III

Item 10.
Directors, Executive Officers and Corporate Governance.

The information required by this Item 10 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with our 2022 annual meeting of shareholders and is incorporated herein by reference.

Item 11.
Executive Compensation

The information required by this Item 11 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with our 2022 annual meeting of shareholders and is incorporated herein by reference.

Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.

The information required by this Item 12 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with our 2022 annual meeting of shareholders and is incorporated herein by reference.

Item 13.
Certain Relationships and Related Transactions, and Director Independence.

The information required by this Item 13 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with our 2022 annual meeting of shareholders and is incorporated herein by reference.

Item 14.
Principal Accounting Fees and Services.

The information required by this Item 14 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2021 in connection with our 2022 annual meeting of shareholders and is incorporated herein by reference.

Part IV

Item 15.
Exhibits, Financial Statement Schedules.

The financial statements of New Fortress Energy Inc. and consolidated subsidiaries are included in Item 8 of this Form 10-K (Form 10-K). Refer to “Index to Financial Statements” set forth of page F-1.

The report of New Fortress Energy’s independent registered public accounting firm (PCAOB ID:42) with respect to the above-referenced financial statements and their report on internal control over financial reporting are included in Item 8 and Item 9A of this Form 10-K at the page numbers F-2 and F-4, respectively. Their consent appears as Exhibit 23.1 of this Form 10-K.

(2) Financial Statement Schedules.

See Schedule II set forth on page F-56.

(b) Exhibits.

The exhibits required to be filed by this Item 15(b) are set forth in the Exhibit Index included below.

Exhibit
Number
Description
Agreement and Plan of Merger, dated as of January 13, 2021, by and among NFE, GMLP Merger Sub, GP Buyer, GMLP and the General Partner (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021).
 
 
Transfer Agreement, dated as of January 13, 2021, by and among GP Buyer, GLNG and the General Partner (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021).
 
 
Agreement and Plan of Merger, dated as of January 13, 2021, by and among NFE, Hygo Merger Sub, Hygo and the Hygo Shareholders (incorporated by reference to Exhibit 2.3 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021).
 
 
Certificate of Formation of New Fortress Energy LLC (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the SEC on November 9, 2018).
 
 
Certificate of Amendment to Certificate of Formation of New Fortress Energy LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the SEC on November 9, 2018).
 
 
First Amended and Restated Limited Liability Company Agreement of New Fortress Energy LLC, dated February 4, 2019 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Certificate of Conversion of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed with the SEC on August 7, 2020).
 
 
Certificate of Incorporation of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 8-K filed with the SEC on August 7, 2020).
 
 
Bylaws of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.3 to the Registrant’s Form 8-K filed with the SEC on August 7, 2020).
   
Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934.

Contribution Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Intermediate LLC, New Fortress Energy Holdings LLC, NFE Atlantic Holdings LLC and NFE Sub LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Amended and Restated Limited Liability Company Agreement of New Fortress Intermediate LLC, dated February 4, 2019 (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
   
New Fortress Energy LLC 2019 Omnibus Incentive Plan (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-8 (File No. 333-229507), filed with the SEC on February 4, 2019).
 
 
Form of Director Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the SEC on December 24, 2018).
 
 
Form of Employee Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q (File No. 001- 38790), filed with the Commission on May 15, 2019).
 
 
Shareholders’ Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and Randal A. Nardone (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Administrative Services Agreement, dated February 4, 2019, by and between New Fortress Intermediate LLC and FIG LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Edens) (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
   
Indemnification Agreement (Guinta) (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Catterall) (incorporated by reference to Exhibit 10.7 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Grain) (incorporated by reference to Exhibit 10.8 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Griffin) (incorporated by reference to Exhibit 10.9 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Mack) (incorporated by reference to Exhibit 10.10 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Nardone) (incorporated by reference to Exhibit 10.11 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Wanner) (incorporated by reference to Exhibit 10.12 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Indemnification Agreement (Wilkinson) (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
 
 
Amendment Agreement dated as February 11, 2019 to Credit Agreement, dated as of August 15, 2018 and as amended and restated as of December 31, 2018, among New Fortress Intermediate LLC, NFE Atlantic Holdings LLC, the subsidiary guarantors from time to time party thereto, lenders parties thereto and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019).

Second Amendment Agreement, dated as of March 13, 2019 to the Credit Agreement, dated as of August 15, 2018 and as amended and restated as of December 31, 2018, and as amended as of February 11, 2019, among New Fortress Intermediate LLC, NFE Atlantic Holdings LLC, the subsidiary guarantors from time to time party thereto, lenders parties thereto and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019).
 
 
Engineering, Procurement and Construction Agreement for the Marcellus LNG Production Facility I, dated January 8, 2019, by and between Bradford County Real Estate Partners LLC and Black & Veatch Construction, Inc. (incorporated by reference to Exhibit 10.17 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the SEC on January 25, 2019).
 
 
Indemnification Agreement, dated as of March 17, 2019, by and between New Fortress Energy LLC and Yunyoung Shin (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019).
 
 
Letter Agreement, dated as of December 3, 2019, by and between NFE Management LLC and Yunyoung Shin. (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2020).
 
 
Indenture, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020).
 
 
Pledge and Security Agreement, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020).
 
 
First Supplemental Indenture, dated December 17, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on December 18, 2020).
 
 
Support Agreement, dated as of January 13, 2021, by and among NFE, GMLP, GLNG and the General Partner (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on January 20, 2021).
 
 
Indenture, dated April 12, 2021, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021).

Pledge and Security Agreement, dated April 12, 2021, by and among the Company, the subsidiary guarantors, from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021).
 
 
Shareholders’ Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and Stonepeak (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021).
 
 
Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and  Morgan Stanley Senior Funding, Inc,. as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021).
   
First amendment to Credit Agreement, dated as of July 16, 2021 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time partly thereto, the several lenders and issuing banks from time to time partly thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent.
   
10.31* Second Amendment to Credit Agreement, dated as of February 28, 2022 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and  Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent.

Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GLNG and certain other parties thereto (incorporated by reference to Exhibit 10.30 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).
 
 
Indemnity Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and certain affiliates of Stonepeak (incorporated by reference to Exhibit 10.31 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).
 
 
Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GMLP, GLNG and certain parties thereto (incorporated by reference to Exhibit 10.32 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).
 
 
Indemnification Agreement, dated as of April 15, 2021, by and between NFE International and GLNG (incorporated by reference to Exhibit 10.33 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 7, 2021).
 
 
Facility Agreement, dated September 18, 2021, by and among Golar Partners Operating LLC as the Borrower, Golar LNG Partners LP and certain subsidiaries of the Borrower, with (i) Citibank N.A. and the lenders from time to time party thereto; (ii) Citigroup Global Markets Limited, Morgan Stanley Senior Funding, Inc. and HSBC Bank USA, N.A. as mandated lead arrangers; (iii) Goldman Sachs Bank USA as arranger; (iv) Citigroup Global Markets Limited and Morgan Stanley Senior Funding, Inc. as bookrunners; (v) Citigroup Global Markets Limited and Morgan Stanley Senior Funding, Inc. as co-ordinators, (vi) Citibank Europe Plc, UK Branch as agent and (vii) Citibank, N.A., London Branch as security agent. (incorporated by reference to Exhibit 10.34 to the Registrant is quarterly report on Form 10-Q, filed with the SEC on November 3, 2021).
   
Consent of Ernst & Young LLP, independent registered public accounting firm.
   
Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
 
 
Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
 
 
101.INS*
Inline XBRL Instance Document
 
 
101.SCH*
Inline XBRL Schema Document
 
 
101.CAL*
Inline XBRL Calculation Linkbase Document
 
 
101.LAB*
Inline XBRL Label Linkbase Document
 
 
101.PRE*
Inline XBRL Presentation Linkbase Document
 
 
101.DEF*
Inline XBRL Taxonomy Extension Definition Linkbase Document
 
 
104*
Cover Page Interactive Data File, formatted in Inline XBRL and contained in Exhibit 101

* Filed as an exhibit to this Annual Report
** Furnished as an exhibit to this Annual Report
† Compensatory plan or arrangement

Item 16.
Form 10-K Summary.

None.

SIGNATURES
 
Pursuant to the requirements of 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 
NEW FORTRESS ENERGY INC.
Date:          March 1, 2022
 
 
 
By:
/s/ Christopher Guinta
 
Name:
Christopher S. Guinta
 
Title:
Chief Financial Officer
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name
 
Title
 
Date
 
 
 
 
 
/s/ Wesley R. Edens
 
Chief Executive Officer and Chairman
(Principal Executive Officer)
 
March 1, 2022
Wesley R. Edens
 
 
 
 
   
/s/ Christopher S. Guinta
 
Chief Financial Officer
(Principal Financial Officer)
 
March 1, 2022
Christopher S. Guinta
 
 
 
 
   
/s/ Yunyoung Shin
 
Chief Accounting Officer
(Principal Accounting Officer)
 
March 1, 2022
Yunyoung Shin
 
 
 
 
   
/s/ Randal A. Nardone
 
Director
 
March 1, 2022
Randal A. Nardone
 
 
   
 
 
 
   
/s/ C. William Griffin
 
Director
 
March 1, 2022
C. William Griffin
 
 
   
 
 
 
   
/s/ John J. Mack
 
Director
 
March 1, 2022
John J. Mack
 
 
   
 
 
 
   
/s/ Matthew Wilkinson
 
Director
 
March 1, 2022
Matthew Wilkinson
 
 
   
 
 
 
   
/s/ David J. Grain
 
Director
 
March 1, 2022
David J. Grain
 
 
   
 
 
 
   
/s/ Desmond Iain Catterall
 
Director
 
March 1, 2022
Desmond Iain Catterall
 
 
   
 
 
 
   
/s/ Katherine E. Wanner
 
Director
 
March 1, 2022
Katherine E. Wanner
 
 
   
 
Index to Consolidated Financial Statements

 
Page
F-2
F-5
F-6
F-7
F-8
F-9

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of New Fortress Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of New Fortress Energy Inc. (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and the financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 1, 2022 expressed an unqualified opinion thereon.

Basis for Opinion

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

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
 
   
Fair value measurements in connection with GMLP and Hygo business combinations
     
Description of the Matter
 
As discussed in Note 4 to the consolidated financial statements, on April 15, 2021, the Company completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”) (collectively, the “Acquisitions”) for total consideration of $1.98 billion and $1.15 billion, respectively. The Acquisitions were accounted for as separate business combinations. The Company’s accounting under the acquisition method included determining the fair value of the acquired assets, liabilities assumed and noncontrolling interests in the acquired entities.

Auditing the Company’s accounting for the Acquisitions was complex due to the significant estimation uncertainty inherent in determining the fair value of the acquired assets, liabilities assumed and noncontrolling interests in the acquired entities. The significant estimation uncertainty was primarily due to the sensitivity of the respective fair values to changes in the underlying assumptions. The significant assumptions used to estimate the fair value of these assets, liabilities and noncontrolling interests included: (i.) discount rates applied to the contractual cash flows associated with the acquired equity method investments, contract intangible assets, assumed debt and noncontrolling interests in the acquired entities, (ii.) the estimated replacement cost of the acquired vessels, and (iii.) market day rates used to measure the fair value of vessel charter contracts.

How We Addressed the Matter in Our Audit
 
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s business combinations process. This included controls over the valuation of acquired assets, liabilities assumed and noncontrolling interests in the acquired entities and management’s review of the significant assumptions described above.
 
To test the estimated fair value of the acquired assets, liabilities assumed and noncontrolling interests in the acquired entities, we performed audit procedures that included, among others, evaluating the valuation methodologies utilized by management and the significant assumptions described above, as well as testing the completeness and accuracy of the underlying data. For example, we compared the significant assumptions utilized to current market and economic trends and to the historical results of the acquired businesses. We also performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the acquired vessels, contract intangible assets, and equity method investments that would result from changes in the assumptions. We involved our internal valuation specialists to assist in evaluating the valuation methodologies used and the significant assumptions described above, including the discount rates utilized and the replacement costs of the acquired vessels.
     

 
Impairment Assessment of Long-Lived Assets
     
Description of the Matter
 
As described in Note 2(j) to the consolidated financial statements, the Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators may include, but are not limited to, factors such as adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for liquified natural gas (“LNG”) to the Company’s operations, early termination of a significant customer contract, the introduction of newer technology, or a decision to discontinue an in-process development project. When such indicators are identified, management determines if long-lived assets or asset groups are impaired by comparing the related undiscounted expected future cash flows to its carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value.
 
Auditing management’s determination of whether impairment indicators exist such that a recoverability test of the Company’s long-lived assets is required, was highly subjective and involves significant judgment. For instance, auditing management’s assessment of events or changes in circumstances that may be an indicator that an asset group is not recoverable was challenging due to the judgment applied in both the identification of such factors, and the evaluation of whether the factors have an impact on the recovery of the carrying value of the asset group.
     
How We Addressed the Matter in Our Audit
 
We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s impairment assessment process. This included management’s controls to review for asset groups that may have been impacted by the impairment indicators described above.
 
To test the Company’s evaluation of potential indicators of impairment of its long-lived assets, our audit procedures included, among others, assessing the methodologies and testing the completeness and accuracy of the Company’s analysis of events or changes in circumstances. For example, we inquired of management (including project development personnel) to understand their evaluation of changes in the regulatory environments of the jurisdictions in which the Company operates and their impact on the recoverability of the related long-lived assets and asset groups.  We also obtained capital budgets and construction bids, among other evidence, to understand management’s plans with respect to in-process development projects.  We considered information about Company’s projects from external sources that support or provide contrary evidence to management’s evaluation of potential impairment indicators.

/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2016.
Philadelphia, Pennsylvania
March 1, 2022

Report of Independent Registered Public Accounting Firm

To the Stockolders and the Board of Directors of New Fortress Energy Inc.

Opinion on Internal Control Over Financial Reporting

We have audited New Fortress Energy Inc.’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, New Fortress Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Hygo Energy Transition Ltd (“Hygo”) and Golar LNG Partners LP (“GMLP”), except for the recognition of goodwill and intangible assets that were included in management’s assessment. Hygo and GMLP are included in the 2021 consolidated financial statements of the Company and constituted approximately 31% and 22% of the Company’s total assets, respectively, as of December 31, 2021 after excluding goodwill and intangible assets and approximately 5% and 14% of the Company’s revenues, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Hygo and GMLP, except for the recognition of goodwill and intangible assets.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2021 consolidated financial statements of the Company and our report dated March 1, 2022 expressed an unqualified opinion thereon.

Basis for Opinion
 
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP
Philadelphia, Pennsylvania
March 1, 2022
 
PART I
FINANCIAL INFORMATION

Item 8.
Financial Statements

New Fortress Energy Inc.
Consolidated Balance Sheets
As of December 31, 2021 and 2020
(in thousands of U.S. dollars, except share and per share amounts)

 
December 31,
2021
   
December 31,
2020
 
Assets
           
Current assets
           
Cash and cash equivalents
 
$
187,509
   
$
601,522
 
Restricted cash
   
68,561
     
12,814
 
Receivables, net of allowances of $164 and $98, respectively
   
208,499
     
76,544
 
Inventory
   
37,182
     
22,860
 
Prepaid expenses and other current assets, net
   
83,115
     
48,270
 
Total current assets
   
584,866
     
762,010
 
                 
Restricted cash
   
7,960
     
15,000
 
Construction in progress
   
1,043,883
     
234,037
 
Property, plant and equipment, net
   
2,137,936
     
614,206
 
Equity method investments
    1,182,013       -  
Right-of-use assets
   
309,663
     
141,347
 
Intangible assets, net
   
142,944
     
46,102
 
Finance leases, net
   
602,675
     
7,044
 
Goodwill
    760,135       -  
Deferred tax assets, net
   
5,999
     
2,315
 
Other non-current assets, net
   
98,418
     
86,030
 
Total assets
 
$
6,876,492
   
$
1,908,091
 
                 
Liabilities
               
Current liabilities
               
Current portion of long-term debt
  $
97,251     $
-  
Accounts payable
 

68,085
   

21,331
 
Accrued liabilities
   
244,025
     
90,352
 
Current lease liabilities
   
47,114
     
35,481
 
Other current liabilities
   
106,036
     
43,986
 
Total current liabilities
   
562,511
     
191,150
 
                 
Long-term debt
   
3,757,879
     
1,239,561
 
Non-current lease liabilities
   
234,060
     
84,323
 
Deferred tax liabilities, net
   
269,513
     
2,330
 
Other long-term liabilities
   
58,475
     
15,641
 
Total liabilities
   
4,882,438
     
1,533,005
 
                 
Commitments and contingencies (Note 21)
           
                 
Stockholders’ equity
               
Class A common stock, $0.01 par value, 750.0 million shares authorized, 206.9 million issued and outstanding as of December 31, 2021; 174.6 million issued and outstanding as of December 31, 2020
   
2,069
     
1,746
 
Additional paid-in capital
   
1,923,990
     
594,534
 
Accumulated deficit
   
(132,399
)
   
(229,503
)
Accumulated other comprehensive (loss) income
   
(2,085
)
   
182
 
Total stockholders’ equity attributable to NFE
   
1,791,575
     
366,959
 
Non-controlling interest
   
202,479
     
8,127
 
Total stockholders’ equity
   
1,994,054
     
375,086
 
Total liabilities and stockholders’ equity
 
$
6,876,492
   
$
1,908,091
 

The accompanying notes are an integral part of these consolidated financial statements.

New Fortress Energy Inc.
Consolidated Statements of Operations and Comprehensive Income (Loss)
For the years ended December 31, 2021, 2020 and 2019
(in thousands of U.S. dollars, except share and per share amounts)

 
 
Year Ended December 31,
 
 
 
2021
   
2020
   
2019
 
Revenues
                 
Operating revenue
 
$
930,816
   
$
318,311
   
$
145,500
 
Vessel charter revenue
    230,809       -       -  
Other revenue
   
161,185
     
133,339
     
43,625
 
Total revenues
   
1,322,810
     
451,650
     
189,125
 
 
                       
Operating expenses
                       
Cost of sales
   
616,010
     
278,767
     
183,359
 
Vessel operating expenses
    51,677       -       -  
Operations and maintenance
   
73,316
     
47,581
     
26,899
 
Selling, general and administrative
   
199,881
     
120,142
     
152,922
 
Transaction and integration costs
    44,671       4,028       -  
Contract termination charges and loss on mitigation sales
   
-
     
124,114
     
5,280
 
Depreciation and amortization
   
98,377
     
32,376
     
7,940
 
Total operating expenses
   
1,083,932
     
607,008
     
376,400
 
Operating income (loss)
   
238,878
     
(155,358
)
   
(187,275
)
Interest expense
   
154,324
     
65,723
     
19,412
 
Other (income) expense, net
   
(17,150
)
   
5,005
     
(2,807
)
Loss on extinguishment of debt, net
   
10,975
     
33,062
     
-
 
Net income (loss) before income from equity method investments and income taxes
   
90,729
     
(259,148
)
   
(203,880
)
Income from equity method investments
    14,443       -       -  
Tax provision
   
12,461
     
4,817
     
439
 
Net income (loss)
   
92,711
     
(263,965
)
   
(204,319
)
Net loss attributable to non-controlling interest
   
4,393
     
81,818
     
170,510
 
Net income (loss) attributable to stockholders
 
$
97,104
   
$
(182,147
)
 
$
(33,809
)
 
                       
Net income (loss) per share – basic
 
$
0.49
   
$
(1.71
)
  $ (1.62 )
Net income (loss) per share – diluted
  $ 0.47     $ (1.71 )   $ (1.62 )
 
                       
Weighted average number of shares outstanding – basic
   
198,593,042
     
106,654,918
      20,862,555  
Weighted average number of shares outstanding – diluted     201,703,176       106,654,918       20,862,555  
 
                       
Other comprehensive income (loss):
                       
Net income (loss)
 
$
92,711
   
$
(263,965
)
 
$
(204,319
)
Currency translation adjustment
   
3,489
     
(2,005
)
   
219
 
Comprehensive income (loss)
   
89,222
     
(261,960
)
   
(204,538
)
Comprehensive loss attributable to non-controlling interest
   
5,615
     
80,025
     
170,699
 
Comprehensive income (loss) attributable to stockholders
 
$
94,837
   
$
(181,935
)
 
$
(33,839
)

The accompanying notes are an integral part of these consolidated financial statements.

New Fortress Energy Inc.
Consolidated Statements of Changes in Stockholders’ Equity
For the years ended December 31, 2021, 2020 and 2019
(in thousands of U.S. dollars, except per share amounts)

 
Members’ Capital
   
Class A shares
   
Class B shares
   
Class A common stock
   
Additional
paid-in
   
Accumulated
   
Accumulated other
comprehensive
   
Non-controlling
   
Total
stockholders’
 
 
Units
   
Amounts
   
Shares
   
Amount
   
Shares
   
Amount
   
Shares
   
Amount
   
capital
   
deficit
   
(loss) income
   
Interest
   
equity
 
Balance as of January 1, 2019
   
67,983,095
   
$
426,741
     
-
   
$
-
     
-
   
$
-
     
-
   
$
-
   
$
-
   
$
(158,423
)
 
$
(11
)
 
$
14,340
   
$
282,647
 
Activity prior to the IPO and related organizational transactions:
                                                                                                       
Net loss
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(7,923
)
   
11
     
(91
)
   
(8,003
)
Effects of the IPO and related organizational transactions:
                                                                                                       
Issuance of Class A shares in the IPO, net of underwriting discount and offering costs
   
-
     
-
     
20,837,272
     
32,136
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
235,874
     
268,010
 
Effects of the reorganization transactions
   
(67,983,095
)
   
(426,741
)
   
-
     
51,092
     
147,058,824
     
-
     
-
     
-
     
-
     
146,420
     
-
     
229,229
     
-
 
Activity subsequent to the IPO and related organizational transactions:
                                                                                                       
Net loss
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(25,897
)
   
-
     
(170,419
)
   
(196,316
)
Other comprehensive loss
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(30
)
   
(189
)
   
(219
)
Share-based compensation expense
   
-
     
-
     
-
     
41,205
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
41,205
 
Exchange of NFI units
   
-
     
-
     
2,716,252
     
6,225
     
(2,716,252
)
   
-
     
-
     
-
     
-
     
-
     
-
     
(6,225
)
   
-
 
Issuance of shares for vested RSUs
   
-
     
-
     
53,572
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
 
Balance as of December 31, 2019
   
-
     
-
     
23,607,096
     
130,658
     
144,342,572
     
-
     
-
     
-
     
-
     
(45,823
)
   
(30
)
   
302,519
     
387,324
 
Cumulative effect of accounting changes
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(1,533
)
   
-
     
(7,780
)
   
(9,313
)
Class A stock issued, net of issuance costs
   
-
     
-
     
-
     
-
     
-
     
-
     
5,882,352
     
59
     
290,712
     
-
     
-
     
-
     
290,771
 
Net loss
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(182,147
)
   
-
     
(81,818
)
   
(263,965
)
Other comprehensive income
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
212
     
1,793
     
2,005
 
Share-based compensation expense
   
-
     
-
     
-
     
4,430
     
-
     
-
     
-
     
-
     
4,313
     
-
     
-
     
-
     
8,743
 
Issuance of shares for vested RSUs
   
-
     
-
     
1,224,436
     
-
     
-
     
-
     
160,317
     
-
     
-
     
-
     
-
     
-
     
-
 
Shares withheld from employees related to share-based compensation, at cost
   
-
     
-
     
-
     
-
     
-
     
-
     
(593,911
)
   
-
     
(6,468
)
   
-
     
-
     
-
     
(6,468
)
Exchange of NFI units
   
-
     
-
     
144,342,572
     
206,587
     
(144,342,572
)
   
-
     
-
     
-
     
-
     
-
     
-
     
(206,587
)
   
-
 
Conversion from LLC to Corporation
   
-
     
-
     
(169,174,104
)
   
(341,675
)
   
-
     
-
     
169,174,104
     
1,687
     
339,988
     
-
     
-
     
-
     
-
 
Dividends
   
-
     
-
     
-
     
-
     
-
     
-
     
-
     
-
     
(34,011
)
   
-
     
-
     
-
     
(34,011
)
Balance as of December 31, 2020
   
-
     
-
     
-
     
-
     
-
     
-
     
174,622,862
     
1,746
     
594,534
     
(229,503
)
   
182
     
8,127
     
375,086
 
Net income (loss)
    -       -       -       -       -       -       -       -       -       97,104       -       (4,393 )     92,711
 
Other comprehensive loss
    -       -       -       -       -       -       -       -       -       -       (2,267 )     (1,222 )     (3,489 )
Share-based compensation expense
    -       -       -       -       -       -       -       -       37,043       -       -       -       37,043
 
Shares issued as consideration in business combinations
    -       -       -       -       -       -       31,372,549       314       1,400,470       -       -       -       1,400,784
 
Issuance of shares for vested RSUs
    -       -       -       -       -       -       1,537,910       9       (9 )     -       -       -       -
 
Shares withheld from employees related to share-based compensation, at cost
    -       -       -       -       -       -       (670,079 )     -       (28,214 )     -       -       -       (28,214 )
Non-controlling interest acquired in business combinations
    -       -       -       -       -       -       -       -       -       -       -       236,570       236,570
 
Deconsolidation of the Eskimo SPV
    -       -       -       -       -       -       -       -       -       -       -       (28,049 )     (28,049 )
Dividends
    -       -       -       -       -       -       -       -       (79,834 )     -       -       (8,554 )     (88,388 )
Balance as of December 31, 2021
    -     $ -       -     $ -       -     $ -       206,863,242     $ 2,069     $ 1,923,990     $ (132,399 )   $ (2,085 )   $ 202,479     $ 1,994,054  

The accompanying notes are an integral part of these consolidated financial statements.

New Fortress Energy Inc.
Consolidated Statements of Cash Flows
For the years ended December 31, 2021, 2020 and 2019
(in thousands of U.S. dollars)

 
 
Year Ended December 31,
 
 
 
2021
   
2020
   
2019
 
Cash flows from operating activities
                 
Net income (loss)
 
$
92,711
   
$
(263,965
)
 
$
(204,319
)
Adjustments for:
                       
Amortization of deferred financing costs and debt guarantee, net
   
14,116
     
10,519
     
5,873
 
Depreciation and amortization
   
99,544
     
33,303
     
8,641
 
(Earnings) of equity method investees
    (14,443 )     -       -  
Dividends received from equity method investees
    21,365       -       -  
Sales-type lease payments received in excess of interest income
    2,348       -       -  
Change in market value of derivatives
    (8,691 )     -       -  
Contract termination charges and loss on mitigation sales
   
-
     
19,114
     
2,622
 
Loss on extinguishment and financing expenses
   
10,975
     
37,090
     
-
 
Deferred taxes
   
(8,825
)
   
2,754
     
392
 
Change in value of Investment of equity securities
    (8,254 )     -       -  
Share-based compensation
   
37,043
     
8,743
     
41,205
 
Other
   
(5,271
)
   
4,341
     
1,247
 
Changes in operating assets and liabilities, net of acquisitions:
                       
(Increase) in receivables
   
(123,583
)
   
(26,795
)
   
(19,754
)
(Increase) Decrease in inventories
   
(11,152
)
   
23,230
     
(50,345
)
(Increase) in other assets
   
(1,839)
     
(35,927
)
   
(39,344
)
Decrease in right-of-use assets
   
28,576
     
41,452
     
-
 
Increase in accounts payable/accrued liabilities
   
17,527
     
55,514
     
3,036
 
Increase (Decrease) in amounts due to affiliates
   
108
     
(1,272
)
   
5,771
 
(Decrease) in lease liabilities
   
(36,126
)
   
(42,094
)
   
-
 
(Decrease) Increase in other liabilities
   
(21,359
)
   
8,427
     
10,714
 
Net cash provided by (used in) operating activities
   
84,770
     
(125,566
)
   
(234,261
)
 
                       
Cash flows from investing activities
                       
Capital expenditures
   
(669,348
)
   
(156,995
)
   
(377,051
)
Cash paid for business combinations, net of cash acquired
   
(1,586,042
)
   
-
     
-
 
Entities acquired in asset acquisitions, net of cash acquired
    (8,817 )     -       -  
Other investing activities
   
(9,354
)
   
(636
)
   
887
 
Net cash used in investing activities
   
(2,273,561
)
   
(157,631
)
   
(376,164
)
 
                       
Cash flows from financing activities
                       
Proceeds from borrowings of debt
   
2,434,650
     
2,095,269
     
347,856
 
Payment of deferred financing costs
   
(37,811
)
   
(36,499
)
   
(8,259
)
Repayment of debt
   
(461,015
)
   
(1,490,002
)
   
(5,000
)
Proceeds from IPO
   
-
     
-
     
274,948
 
Proceeds from issuance of Class A common stock
   
-
     
291,992
      -
 
Payments related to tax withholdings for share-based compensation
   
(30,124
)
   
(6,413
)
   
-
 
Payment of dividends
   
(88,756
)
   
(33,742
)
   
-
 
Payment of stock issuance costs
   
-
     
(1,107
)
   
(6,938
)
Net cash provided by financing activities
   
1,816,944
     
819,498
     
602,607
 
 
                       
   Impact of changes in foreign exchange rates on cash and cash equivalents
    6,541       -       -  
Net (decrease) increase in cash, cash equivalents and restricted cash
   
(365,306
)
   
536,301
     
(7,818
)
Cash, cash equivalents and restricted cash – beginning of period
   
629,336
     
93,035
     
100,853
 
Cash, cash equivalents and restricted cash – end of period
 
$
264,030
   
$
629,336
   
$
93,035
 
 
                       
Supplemental disclosure of non-cash investing and financing activities:
                       
Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions
 
$
108,790
   
$
(12,786
)
 
$
(48,150)
 
Liabilities associated with consideration paid for entities acquired in asset acquisitions
    10,520       -       -  
Consideration paid in shares for business combinations
    1,400,784       -       -  
Cash paid for interest, net of capitalized interest
   
154,249
     
27,255
     
6,765
 
Cash paid for taxes
   
17,319
     
58
     
28
 
 
The accompanying notes are an integral part of these consolidated financial statements.


1.
Organization

New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, is a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs and is engaged in providing energy and development services to end-users worldwide seeking to convert their operating assets from diesel or heavy fuel oil to LNG. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica, Brazil and Mexico. Subsequent to the Mergers (defined below), the Company has marine operations with vessels operating under time charters and in the spot market globally.

On April 15, 2021, the Company completed the acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”); referred to as the “Hygo Merger” and “GMLP Merger,” respectively and, collectively, the “Mergers”. NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger. NFE paid $3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interests 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 operations of Hygo and GMLP and their subsidiaries have been included in the Company’s consolidated financial statements for the period subsequent to the Mergers.

As a result of the Hygo Merger, the Company acquired a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”) and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), as well as the Barcarena Facility and Barcarena 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, the Company 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 the Company’s existing facilities and international project pipeline. The majority of the FSRUs are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market.

The Company currently conducts its business through two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the business.

2.
Significant accounting policies

The principal accounting policies adopted are set out below.

(a)
Basis of presentation and principles of consolidation

The accompanying consolidated financial statements contained herein were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned consolidated subsidiaries. The ownership interest of other investors in consolidated subsidiaries is recorded as a non-controlling interest. All significant intercompany transactions and balances have been eliminated on consolidation. Certain prior year amounts have been reclassified to conform to current year presentation.


A variable interest entity (“VIE”) is an entity that by design meets any of the following characteristics: (1) lacks sufficient equity to allow the entity to finance its activities without additional subordinated financial support; (2) as a group, equity investors do not have the ability to make significant decisions relating to the entity’s operations through voting rights, do not have the obligation to absorb the expected losses or do not have the right to receive residual returns of the entity; or (3) the voting rights of some investors are not proportional to their obligations to absorb the expected losses of the entity, their rights to receive the expected residual returns of the entity, or both, and substantially all of the entity’s activities either involve or are conducted on behalf of an investor that has disproportionately few voting rights. The primary beneficiary of a VIE is required to consolidate the assets and liabilities of the VIE. The primary beneficiary is the party that has both (1) the power to direct the economic activities of the VIE that most significantly impact the VIE’s economic performance; and (2) through its interest in the VIE, the obligation to absorb the losses or the right to receive the benefits from the VIE that could potentially be significant to the VIE.



The sale and leaseback financings of certain vessels acquired in the Mergers were consummated with VIEs. As part of these financings, the asset was sold to a single asset entity of the lending bank and then leased back. While the Company does not hold an equity investment in these lending entities, these entities are VIEs, and the Company has a variable interest in these lending entities due to the guarantees and fixed price repurchase options that absorb the losses of the VIE that could potentially be significant to the entity. The Company has concluded that it has the power to direct the economic activities that most impact the economic performance as it controls the significant decisions relating to the assets and it has the obligation to absorb losses or the right to receive the residual returns from the leased asset. Therefore, the Company consolidates these lending entities; as NFE has no equity interest in these VIEs, all equity attributable to these VIEs is included in non-controlling interest in the consolidated financial statements. Transactions between our wholly-owned subsidiaries and these VIEs are eliminated in consolidation, including sale leaseback transactions.



Noncontrolling interests are classified as a separate component of equity on the consolidated balance sheets and consolidated statements of changes in stockholders’ equity. Additionally, net income (loss) and comprehensive income (loss) attributable to noncontrolling interests are reflected separately from consolidated net income (loss) and comprehensive income (loss) in the consolidated statements of operations and comprehensive income (loss) and consolidated statements of changes in stockholders’ equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and noncontrolling interests. Losses continue to be attributed to the noncontrolling interests, even when the noncontrolling interests’ basis has been reduced to zero.

(b)
Use of estimates
 
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include relative fair value allocations between revenue and lease components of contracts with customers, the incremental borrowing rates used in the determination of lease liabilities, total consideration and fair value of identifiable net assets related to acquisitions and the fair value of equity awards granted to both employees and non-employees. Management evaluates its estimates and related assumptions regularly. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.
 
(c)
Foreign currencies

The Company has certain foreign subsidiaries in which the functional currency is the local currency. All of the assets and liabilities of these subsidiaries are translated to U.S. dollars at the exchange rate in effect at the balance sheet date; income and expense accounts are translated at average rates for the period. The effects of translating financial statements of foreign operations into our reporting currency are recognized as a cumulative translation adjustment in accumulated other comprehensive income (loss).

The Company also has foreign subsidiaries that have a functional currency of the U.S. dollar. Purchases and sales of assets and income and expense items denominated in foreign currencies are remeasured into U.S. dollar amounts on the respective dates of such transactions. Net realized foreign currency gains or losses relating to the differences between these recorded amounts and the U.S. dollar equivalent actually received or paid are included within Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss). Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in accumulated other comprehensive income (loss). Accumulated foreign currency translation adjustments are reclassified from accumulated other comprehensive income (loss) to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. If the Company commits to a plan to sell or liquidate a foreign entity, accumulated foreign currency translation adjustments would be included in carrying amounts in impairment assessments.

(d)
Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

(e)
Restricted cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on the consolidated balance sheets.

(f)
Receivables

Receivables are reported at amortized cost, net of an allowance for current expected credit losses. Amounts are written off against the allowance when management is certain that outstanding amounts will not be collected. The Company estimates expected credit losses based on relevant information about the current credit quality of customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectability of the reported amount. Credit loss expense, inclusive of credit loss expense on all categories of financial assets, is recorded within Selling, general and administrative in the consolidated statements of operations and comprehensive income (loss).

(g)
Inventories

LNG and natural gas inventories and automotive diesel oil inventories are recorded at weighted average cost, and materials and other inventory are recorded at cost. The Company’s cost to convert from natural gas to LNG, which primarily consists of labor, depreciation and other direct costs to operate liquefaction facilities, is reflected in Inventory on the consolidated balance sheets.

Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the consolidated statements of operations and comprehensive income (loss).

LNG is subject to “boil-off,” a natural loss of gas volume over time when LNG is exposed to environments with temperatures above its optimum storage state. Boil-off losses are expensed through Cost of sales in the consolidated statements of operations and comprehensive income (loss) in instances where gas cannot be contained and recycled back into the production process.

(h)
Construction in progress

Construction in progress is recorded at cost, and at the point at which the constructed asset is put into use, the full cost of the asset is reclassified from Construction in progress to Property, plant and equipment, net or Finance leases, net on the consolidated balance sheets. Construction progress payments, engineering costs and other costs directly relating to the asset under construction are capitalized during the construction period, provided the completion of the construction project is deemed probable or if the costs are associated with activities that could be utilized in future projects. Depreciation is not recognized during the construction period.

The interest cost associated with major development and construction projects is capitalized during the construction period and included in the cost of the project in Construction in progress.
 
(i)
Property, plant and equipment, net
 

Property, plant and equipment is initially recorded at cost. Expenditures for construction activities and betterments that extend the useful life of the asset are capitalized. Vessel refurbishment costs are capitalized and depreciated over the vessels’ remaining useful economic lives. Refurbishment costs increase the capacity or improve the efficiency or safety of vessels and equipment. Expenditures for routine maintenance and repairs for assets in the Terminals and Infrastructure segment are charged to expense as incurred within Operations and maintenance in the consolidated statements of operations and comprehensive income (loss); such expenditures for assets in the Ships segment that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred within Vessel operating expenses.



Major maintenance and overhauls of the Company’s power plant and terminals are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul. Drydocking expenditures are capitalized when incurred and amortized over the period until the next anticipated drydocking, which is generally five years. For vessels, the Company utilizes the “built-in overhaul” method of accounting. The built-in overhaul method is based on the segregation of vessel costs into those that should be depreciated over the useful life of the vessel and those that require drydocking at periodic intervals to reflect the different useful lives of the components of the assets. The estimated cost of the drydocking component is depreciated until the date of the first drydocking following acquisition of the vessel, upon which the cost is capitalized and the process is repeated. If drydocking occurs prior to the expected timing, a cumulative adjustment to recognize the change in expected timing of drydocking is recognized within Depreciation and amortization in the consolidated statements of operations and comprehensive income (loss).



The Company depreciates property, plant and equipment less the estimate residual value using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives:


 
Useful life (Yrs)
Vessels  5-30
Terminal and power plant equipment
4-24
CHP facilities
4-20
Gas terminals
5-24
ISO containers and associated equipment
3-25
LNG liquefaction facilities
20-40
Gas pipelines
4-24
Leashold improvements
2-20

The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted.

Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in the consolidated statements of operations and comprehensive income (loss). When a vessel is disposed, any unamortized drydocking expenditure is recognized as part of the gain or loss on disposal in the period of disposal.

(j)
Impairment of long-lived assets
 
The Company performs 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 the Company operates, unfavorable events impacting the supply chain for LNG to the Company’s 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.

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. The Company did not identify any indicators of impairment and did not record an impairment during the years ended December 31, 2021, 2020 and 2019.

(k)
Investments in equity securities
 
Investments in equity securities are carried at fair value and included in Other non-current assets on the consolidated balance sheets, with gains or losses recorded in earnings in Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss).

(l)
Intangible assets

Upon a business combination or asset acquisition, the Company may obtain identifiable intangible assets. Intangible assets with a finite life are amortized over the estimated useful life of the asset under the straight-line method.

Indefinite lived intangible assets are not amortized. Intangible assets with an indefinite useful life are tested for impairment on an annual basis or more frequently if changes in circumstances indicate that it is more likely than not that the asset is impaired. Indefinite lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense in the consolidated statements of operations and comprehensive income (loss).

(m)
Goodwill


Goodwill includes the excess of the purchase price over the fair value of the net tangible and intangible assets associated with the Mergers.



The Company reviews the carrying values of goodwill at least annually to assess impairment since these assets are not amortized. An annual impairment review is conducted as of October 1st of each year. Additionally, the Company reviews the carrying value of goodwill whenever events or changes in circumstances indicate that its carrying amount may not be recoverable.



For an annual goodwill impairment assessment, an optional qualitative analysis may be performed. If the option is not elected or if it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then a two-step goodwill impairment test is performed to identify potential goodwill impairment and to measure an impairment loss. A qualitative analysis was elected for the year ended December 31, 2021.



A goodwill impairment assessment compares the fair value of a respective reporting unit with its carrying amount, including goodwill. The estimate of fair value of the respective reporting unit is based on the best information available as of the date of assessment, which primarily incorporates assumptions about operating results, business plans, income projections, anticipated future cash flows and market data. If goodwill is determined to be impaired, an impairment loss, measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.



There was no impairment of goodwill for the year ended December 31, 2021.

(o)
Long-term debt and debt issuance costs

Costs directly related to the issuance of debt are reported on the consolidated balance sheets as a reduction from the carrying amount of the recognized debt liability and amortized over the term of the debt using the effective interest method. Unamortized debt issuance costs associated with the revolving credit agreement, commercial paper and other similar arrangements are presented as an asset (regardless of whether there are any amounts outstanding under the credit facility) and amortized over the life of the particular arrangement. Interest and related amortization of debt issuance costs recognized during major development and construction projects are capitalized and included in the cost of the project.

(p)
Contingencies

The Company may be involved in legal actions in the ordinary course of business, including governmental and administrative investigations, inquiries and proceedings concerning employment, labor, environmental and other claims. The Company will recognize a loss contingency in the consolidated financial statements when it is probable a liability has been incurred and the amount of the loss can be reasonably estimated. The Company will disclose any loss contingencies that do not meet both conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.

(q)
Revenue recognition

Terminals and Infrastructure

Within the Terminals and Infrastructure segment, the Company’s 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 the Company’s 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 by the Company 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 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 is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, 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, the Company has presented Operating revenue on an aggregated basis.



The Company has 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.



The Company’s 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 the Company’s operating leases, the Company has elected the practical expedient to combine revenue for the sale of natural gas or LNG and operating lease income as the timing and pattern of transfer of the components are the same. The Company has concluded that the predominant component of the transaction is the sale of natural gas or LNG and therefore has not separated 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). The Company allocates 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. The Company estimates 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. Revenue from these development services is recognized over time as the Company transfers 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 the Company recognizes revenue for the interest income component over the term of the financing as Other revenue.



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.



The Company collects sales taxes from its customers based on sales of taxable products and remits such collections to the appropriate taxing authority. The Company has 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.



The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects 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, the Company makes an assessment on whether the charter contract is an operating lease or a finance lease. In making the classification assessment, the Company estimates 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 the Company believes 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. The Company assesses 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).



Revenue includes lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenue generated from charters contracts is 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 income (loss). Lease payments include fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, the Company has 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 become probable or occur.



Repositioning fees are included in Vessel charter revenues and are recognized at the end of the charter when the fee becomes fixed. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee is recognized evenly over the term of the charter.



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.



The Company’s LNG carriers may participate in an LNG carrier pool collaborative arrangement with Golar LNG Limited, referred to as the Cool 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 an 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.


The Company is primarily responsible for fulfilling the performance obligations in the time charters of vessels owned by the Company, and the Company is the principal in such time charters. Revenue and expenses for charters of the Company’s vessels that participate in the Cool Pool are presented on a gross basis within Vessel charter revenues and Vessel operating expenses, respectively, in the consolidated statements of operations and comprehensive income (loss). The Company’s allocation of its 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 income (loss).

(r)
Leases, as lessee

Effective January 1, 2020, the Company adopted Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842), using the modified retrospective approach. The Company has entered into lease agreements for the use of LNG vessels, marine port space, office space, land and equipment. Right-of-use (“ROU”) assets recognized for these leases represent the Company’s right to use an underlying asset for the lease term, and the lease liabilities represent the Company’s obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the estimated present value of fixed lease payments over the lease term.

Leases with terms of 12 months or less are excluded from ROU assets and lease liabilities on the balance sheet, and short-term lease payments are recognized on a straight-line basis over the lease term. Variable payments under short-term leases are recognized in the period in which the obligation that triggers the variable payment becomes probable.

The Company, as lessee, has also elected the practical expedient not to separate lease and non-lease components for marine port space, office space, land and equipment leases. The Company separates the lease and non-lease components for LNG vessel leases. The allocation of lease payments between lease and non-lease components has been determined based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone price to lease a bareboat LNG vessel. The fair value of the non-lease component is estimated based on the estimated standalone price of operating the respective vessel, inclusive of the costs of the crew and other operating costs.

The Company has elected the land easement practical expedient, which allows the Company to continue to account for pre-existing land easements as intangible assets under the accounting policy that existed before adoption of ASC 842 Leases.

(s)
Share-based compensation


The Company adopted the New Fortress Energy Inc. 2019 Omnibus Incentive Plan (the “Incentive Plan”), effective as of February 4, 2019. Under the Incentive Plan, the Company may issue options, share appreciation rights, restricted shares, restricted share units (“RSUs”), share bonuses or other share-based awards to selected officers, employees, non-employee directors and select non-employees of NFE or its affiliates. The Company accounts for share-based compensation in accordance with ASC 718, Compensation and ASC 505, Equity, which require all share-based payments to employees and members of the board of directors to be recognized as expense in the consolidated financial statements based on their grant date fair values. The Company has elected not to estimate forfeitures of its share-based compensation awards but recognizes the reversal in compensation expense in the period in which the forfeiture occurs.



During the first quarter of 2020 and 2021, the Company granted performance share units (“PSUs”) to certain employees and non-employees. The PSUs contain a performance condition, and vesting is determined based on achievement of a performance metric in the year subsequent to the grant. Compensation expense is recognized on a straight-line basis over the service period based on the expected attainment of a performance metric. At each reporting period, the Company reassesses the probability of the achievement of the performance metric, and any increase or decrease in share-based compensation expense resulting from an adjustment in the number of shares expected to vest is treated as a cumulative catch-up in the period of adjustment.

(t)
Lessor expense recognition



Vessel operating expenses, which are recognized when incurred, include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and third-party management fees. Voyage expenses 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.



Initial direct costs include costs directly related to the negotiation and consummation of the lease are deferred and recognized in Vessel operating expenses over the lease term.


(u)
Transaction and integration costs



Transaction and integration costs is comprised of costs related to business combinations and include advisory, legal, accounting, valuation and other professional or consulting fees. This caption also includes gains or losses recognized in connection with business combinations, including the settlement of preexisting relationships between the Company and an acquired entity. Financing costs which are not deferred as part of the cost of the financing on the balance sheet are recognized within this caption including fees associated with debt modifications.


(v)
Contract termination charges and loss on mitigation sales


The Company has long-term supply agreements to purchase LNG, and the Company may incur termination charges to the extent that the Company cancels such contractual arrangements. Further, if the Company is unable to take physical possession of a portion of the contracted quantity of LNG due to capacity limitations, the supplier will attempt to sell the undelivered quantity through a mitigation sale. The Company may incur a loss on a mitigation sale if the cargo is unable to be sold for a price greater than the contracted price. These costs are included in a separate line in the consolidated statements of operations and comprehensive income (loss) because such costs are not related to inventory delivered to the Company’s customers.



During the year ended December 31, 2020, the Company recognized a termination charge of $105,000 associated with an agreement with one of the Company’s LNG suppliers to terminate the obligation to purchase any LNG from this supplier for the remainder of 2020. Loss on mitigation sales of $19,114 were recognized during the year ended December 31, 2020.  We did not have such transactions during the year ended December 31, 2021.


(w)
Taxation

The Company accounts for income taxes in accordance with ASC 740, Accounting for Income Taxes (“ASC 740”), under which deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts and the tax bases of assets and liabilities by applying the enacted tax rates in effect for the year in which the differences are expected to reverse. Such net tax effects on temporary differences are reflected on the Company’s consolidated balance sheets as deferred tax assets and liabilities. Deferred tax assets are reduced by a valuation allowance when the Company believes that it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

The Company recognizes the effect of tax positions only if those positions are more likely than not of being sustained. Recognized tax positions are measured at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement with the relevant tax authority. Conclusions reached regarding tax positions are continually reviewed based on ongoing analyses of tax laws, regulations and interpretations thereof. To the extent that the Company’s assessment of the conclusions reached regarding tax positions changes as a result of the evaluation of new information, such change in estimate will be recorded in the period in which such determination is made. The Company reports interest and penalties relating to an underpayment of income taxes, if applicable, as a component of income tax expense.

The Company has elected to treat amounts incurred under the global intangible low-taxed income (“GILTI”) rules as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.

Other taxes

Certain subsidiaries may be subject to payroll taxes, excise taxes, property taxes, sales and use taxes, in addition to income taxes in foreign countries in which they conduct business. In addition, certain subsidiaries are exposed to local state taxes, such as franchise taxes. Local state taxes that are not income taxes are recorded within Other expense (income), net in the consolidated statements of operations and comprehensive income (loss).

(x)
Net income (loss) per share


Basic net income (loss) per share (“EPS”) is computed by dividing net income (loss) attributable to Class A common stock by the weighted average number of shares of Class A common stock outstanding.



The dilutive effect of outstanding awards, if any, is reflected in diluted earnings per share by application of the treasury stock method or if-converted method, as applicable.


(y)
Acquisitions


Business combinations are accounted for under the acquisition method. On acquisition, the identifiable assets acquired and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the purchase price over the fair values of the identifiable net assets acquired is recognized as goodwill.  Acquisition related costs are expensed as incurred as Transaction and integration costs in the statements of operations and comprehensive income (loss). The results of operations of acquired businesses are included in the Company’s consolidated statements of operations and comprehensive income (loss) from the date of acquisition.



If the assets acquired do not meet the definition of a business, the transaction is accounted for as an asset acquisition and no goodwill is recognized. Costs incurred in conjunction with asset acquisitions are included in the purchase price, and any excess consideration transferred over the fair value of the net assets acquired is reallocated to the identifiable assets based on their relative fair values.


(z)
Equity method investments
 
The Company accounts for investments in entities over which the Company has significant influence, but do not meet the criteria for consolidation, under the equity method of accounting. Under the equity method of accounting, the Company’s investment is recorded at cost, or in the case of equity method investments acquired as part of the Mergers, at the acquisition date fair value of the investment. The carrying amount is adjusted for the Company’s share of the earnings or losses, and dividends received from the investee reduce the carrying amount of the investment. The Company allocates the difference between the fair value of investments acquired in the Mergers and the Company’s proportionate share of the carrying value of the underlying assets, or basis difference, across the assets and liabilities of the investee. The basis difference assigned to amortizable net assets is included in Income (loss) from equity method investments in the consolidated statements of operations and comprehensive income (loss). When the Company’s share of losses in an investee equals or exceeds the carrying value of the investment, no further losses are recognized unless the Company has incurred obligations or made payments on behalf of the investee.

The Company periodically assesses if impairment indicators exist at our equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment expense when the loss in value is deemed other-than-temporary and included in Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss).

(aa)
Loss of control of subsidiary

When there is a loss of control over a subsidiary, the Company de-consolidates as of the date the Company ceases to have a financial interest. The Company accounts for the deconsolidation of a subsidiary by recognizing a gain or loss in the  consolidated statements of operations and comprehensive income (loss), measured by the difference between the aggregate of the fair value of the consolidation received, fair value of any retained non-controlling interest in the former subsidiary and the carrying amount of any non-controlling interest in the former subsidiary with the carrying amount of the former subsidiary’s assets and liabilities. If a change of ownership interest causes a loss of control of a foreign entity, in addition to de-recognizing the assets and liabilities, the Company also de-recognize any amounts previously recorded in other comprehensive income (loss).

(ab)
Guarantees

Guarantees issued by the Company, excluding those that are guaranteeing the Company’s own performance, are recognized at fair value at the time that the guarantees are issued and recognized in Other current liabilities and Other non-current liabilities on the consolidated balance sheets. The guarantee liability is amortized each period as a reduction to Selling, general and administrative expenses. If it becomes probable that the Company will have to perform under a guarantee, the Company will recognize an additional liability if the amount of the loss can be reasonably estimated.

(ac)
Derivatives

As part of the Mergers, the Company acquired derivative positions that were used to reduce market risks associated with interest rates and foreign exchange rates. The Company also accounts for arrangements that require the Company to pay sellers contingent payments in asset acquisitions as derivatives. All derivative instruments are initially recorded at fair value as either assets or liabilities on the consolidated balance sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative, unless they qualify for a Normal Purchases and Normal Sales (“NPNS”) exception. The Company has not designated any derivates as cash flow or fair value hedges; however, certain instruments may be considered economic hedges.


Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered. While these contracts are considered derivative financial instruments under ASC 815, Derivatives and Hedging, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.

3.
Adoption of new and revised standards

(a)
New standards, amendments and interpretations issued but not effective for the year beginning January 1, 2021:

In August 2020, the Financial Accounting Standards Board (“FASB”) issued ASU 2020-06,  Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. ASU 2020-06 requires entities to provide expanded disclosures about the terms and features of convertible instruments and amends certain guidance in ASC 260, Earnings per Share, on the computation of EPS for convertible instruments and contracts on an entity’s own equity. ASU 2020-06 is effective for public companies for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years, with early adoption of all amendments in the same period permitted. The Company will adopt this guidance in the first quarter of 2022 and does not expect it to have a material impact on the Company’s financial position, results of operations or cash flows.

(b)
New and amended standards adopted by the Company:


In December 2019, FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes, including removing certain exceptions related to the general principles in ASU 740, Income Taxes. ASU 2019-12 also clarifies and simplifies other aspects of the accounting for income taxes. The adoption of this guidance in the first quarter of 2021 did not have a material impact on the Company’s financial position, results of operations or cash flows.



In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The guidance provides temporary optional expedients and exceptions to current accounting guidance on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and generally can be applied to applicable contract modifications and hedge relationships prospectively through December 31, 2022. The adoption of this guidance did not have a significant impact on the Company’s financial statements.



Refer to Note 5. VIEs and Note 19. Debt for discussion of the use of the London Interbank Offered Rate (“LIBOR”) in connection with the Company’s financing arrangements. The majority of the Company’s debt facilities include fallback provisions that contemplate the replacement of LIBOR. The discontinuation of LIBOR will require these arrangements to be modified to utilize an alternative interest rate. The Company has made a policy election to adopt the optional expedients related to contract modifications related to its debt and certain other arrangements and will apply the relief on a prospective basis as modifications are made. The Company continues to monitor the activities of regulators and financial institutions to transition to an alternative reference rate and to review additional arrangements for references to LIBOR. Accordingly, the Company may make additional optional elections in the future.

4.
Acquisitions

Hygo Merger

On April 15, 2021, the Company completed the acquisition of all of the outstanding common and preferred shares representing all voting interests of Hygo, a 50-50 joint venture between Golar LNG Limited (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd., a fund managed by Stonepeak Infrastructure Partners (“Stonepeak”), in exchange for 31,372,549 shares of NFE Class A common stock and $580,000 in cash. The acquisition of Hygo expands the Company’s footprint in South America with three gas-to-power projects in Brazil’s large and fast-growing market.

Based on the closing price of NFE’s common stock on April 15, 2021, the total value of consideration in the Hygo Merger was $1.98 billion, shown as follows:

Consideration
       
As of
April 15, 2021
 
Cash consideration for Hygo Preferred Shares
 
$
180,000
       
Cash consideration for Hygo Common Shares
   
400,000
       
Total Cash Consideration
         
$
580,000
 
Merger consideration to be paid in shares of NFE Common Stock
   
1,400,784
         
Total Non-Cash Consideration
           
1,400,784
 
Total Consideration
         
$
1,980,784
 

The Company has determined it is the accounting acquirer of Hygo, which will be accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction has been allocated to identifiable assets acquired, liabilities assumed and non-controlling interests of Hygo based on their respective estimated fair values as of the closing date.

The process of estimating the fair values of certain tangible assets, identifiable intangible assets and assumed liabilities requires the use of judgment, including determining the appropriate assumptions and estimates. As of December 31, 2021, the allocation of the purchase price is preliminary due to the finalization of the evaluation of tax related matters. The purchase price allocation will be finalized once such matters have been resolved. Accordingly, the fair value estimates presented below relating to this item is subject to change within the measurement period not to exceed one year from the date of acquisition. Fair values assigned to the assets acquired, liabilities assumed and non-controlling interests of Hygo as of the closing date were as follows:

Hygo
 
As of
April 15, 2021
 
Assets Acquired
     
Cash and cash equivalents
 
$
26,641
 
Restricted cash
   
48,183
 
Accounts receivable
   
5,126
 
Inventory
   
1,022
 
Other current assets
   
8,095
 
Assets under development
   
128,625
 
Property, plant and equipment, net
   
385,389
 
Equity method investments
   
823,521
 
Finance leases, net
   
601,000
 
Deferred tax assets, net
   
1,065
 
Other non-current assets
   
52,996
 
Total assets acquired:
 
$
2,081,663
 
Liabilities Assumed
       
Current portion of long-term debt
 
$
38,712
 
Accounts payable
   
3,059
 
Accrued liabilities
   
39,149
 
Other current liabilities
   
13,495
 
Long-term debt
   
433,778
 
Deferred tax liabilities, net
   
254,949
 
Other non-current liabilities
   
21,520
 
Total liabilities assumed:
   
804,662
 
Non-controlling interest
   
40,414
 
Net assets acquired:
   
1,236,587
 
Goodwill
 
$
744,197
 

For the year ended December 31, 2021, the Company made certain measurement period adjustments to the assets acquired, liabilities assumed and non-controlling interests of Hygo due to additional information utilized to determine fair value during the measurement period. The measurement period adjustment impacted the fair value of debt assumed, including associated impacts to non-controlling interests and deferred tax liabilities. The measurement period adjustment decreased goodwill by $2,740, and the Company recognized additional interest expense of $1,088 for the year ended December 31, 2021.

The fair value of Hygo’s non-controlling interest (“NCI”) as of April 15, 2021 was $40,414, including the fair value of the net assets of VIEs that Hygo has consolidated. These VIEs are special purpose vehicles (“SPV”) for the sale and leaseback of certain vessels, and Hygo has no equity investment in these entities. The fair value of NCI was determined based on the valuation of the SPV’s external debt and the lease receivable asset associated with the sales leaseback transaction with Hygo’s subsidiary, using a discounted cash flow method.

The fair value of receivables acquired from Hygo is $8,009, which approximates the gross contractual amount; no material amounts are expected to be uncollectible.

Goodwill is calculated as the excess of the purchase price over the net assets acquired. Goodwill represents access to additional LNG and natural gas distribution systems and power markets, including workforce that will allow the Company to rapidly develop and deploy LNG to power solutions. While the goodwill is not deductible for local tax purposes, it is treated as an amortizable expense for the U.S. global intangible low-taxed income (“GILTI”) computation.

The Company’s results of operations for the year ended December 31, 2021 include Hygo’s result of operations from the date of acquisition, April 15, 2021, through December 31, 2021. Revenue and net income attributable to Hygo during the period was $67,089 and $4,551, respectively.

GMLP Merger

On April 15, 2021, the Company completed the acquisition of all of the outstanding common units, representing all voting interests, of GMLP in exchange for $3.55 in cash per common unit and for each of the outstanding membership interest of GMLP’s general partner. In conjunction with the closing of the GMLP Merger, NFE simultaneously extinguished a portion of GMLP’s debt for total consideration of $1.15 billion.

With the acquisition of GMLP, the Company gained vessels to support the existing terminals and business development pipeline, as well as an interest in a floating natural gas liquefaction facility (“FLNG”), which is expected to provide consistent cash flow streams under a long-term tolling arrangement. The interest in the FLNG facility also provides the Company access to intellectual property that will be used to develop future FLNG solutions.

The consideration paid by the Company in the GMLP Merger was as follows:

Consideration
       
As of
April 15, 2021
 
GMLP Common Units ($3.55 per unit x 69,301,636 units)
 
$
246,021
       
GMLP General Partner Interest ($3.55 per unit x 1,436,391 units)
   
5,099
       
Partnership Phantom Units ($3.55 per unit x 58,960 units)
   
209
       
Cash Consideration
         
$
251,329
 
GMLP debt repaid in acquisition
   
899,792
         
Total Cash Consideration
           
1,151,121
 
Cash settlement of preexisting relationship
   
(3,978
)
       
Total Consideration
         
$
1,147,143
 

The Company has determined it is the accounting acquirer of GMLP, which will be accounted for under the acquisition method of accounting for business combinations. The total purchase price of the transaction has been allocated to identifiable assets acquired, liabilities assumed and non-controlling interests of GMLP based on their respective estimated fair values as of the closing date.


The process of estimating the fair values of certain tangible assets, identifiable intangible assets and assumed liabilities requires the use of judgment, including determining the appropriate assumptions and estimates. As of December 31, 2021, the allocation of the purchase price is preliminary due to the finalization of the evaluation of tax related matters. The purchase price allocation will be finalized once such matters have been resolved. Accordingly, the fair value estimates presented below relating to this item is subject to change within the measurement period not to exceed one year from the date of acquisition. Fair values assigned to the assets acquired, liabilities assumed and non-controlling interests of GMLP as of the closing date were as follows:

GMLP
 
As of
April 15, 2021
 
Assets Acquired
     
Cash and cash equivalents
 
$
41,461
 
Restricted cash
   
24,816
 
Accounts receivable
   
3,195
 
Inventory
   
2,151
 
Other current assets
   
2,789
 
Equity method investments
   
355,500
 
Property, plant and equipment, net
   
1,063,215
 
Intangible assets, net
   
106,500
 
Deferred tax assets, net
   
963
 
Other non-current assets
   
4,400
 
Total assets acquired:
 
$
1,604,990
 
Liabilities Assumed
       
Current portion of long-term debt
 
$
158,073
 
Accounts payable
   
3,019
 
Accrued liabilities
   
17,226
 
Other current liabilities
   
73,774
 
Deferred tax liabilities, net
   
14,907
 
Other non-current liabilities
   
10,630
 
Total liabilities assumed:
   
277,629
 
Non-controlling interest
   
196,156
 
Net assets to be acquired:
   
1,131,205
 
Goodwill
 
$
15,938
 

For the year ended December 31, 2021, the Company made certain measurement period adjustments to the assets acquired, liabilities assumed and non-controlling interests of GMLP due to additional information utilized to determine fair value during the measurement period. The measurement period adjustments impacted the fair value of intangible assets acquired and debt assumed, including associated impacts to deferred tax liabilities and non-controlling interests. The measurement period adjustments increased goodwill by $14,273, and the Company recognized amortization of $11,119 of the discount on debt and amortization of $415 of intangibles as an addition to interest expense and amortization expense, respectively, for the period after the GMLP Merger.

The fair value of GMLP’s NCI as of April 15, 2021 was $196,156, which represents the fair value of other investors’ interest in the Mazo, GMLP’s preferred units which were not acquired by the Company and the fair value of net assets of an SPV formed for the purpose of a sale and leaseback of the Eskimo. The fair value of GMLP’s preferred units and the valuation of the SPV’s external debt and the lease receivable asset associated with the sale leaseback transaction have been estimated using a discounted cash flow method.

The fair value of receivables acquired from GMLP is $4,797, which approximates the gross contractual amount; no material amounts are expected to be uncollectible.

The Company acquired favorable and unfavorable leases for the use of GMLP’s vessels. The fair value of the favorable contracts is $106,500 and the fair value of the unfavorable contracts is $13,400. The total weighted average amortization period is approximately three years; the favorable contract asset has a weighted average amortization period of approximately three years and the unfavorable contract liability has a weighted average amortization period of approximately one year.

The Company and GMLP had an existing lease agreement prior to the GMLP Merger. As a result of the acquisition, the lease agreement and any associated receivable and payable balances were effectively settled. The lease agreement also included provisions that required a subsidiary of NFE to indemnify GMLP to the extent that GMLP incurred certain tax liabilities as a result of the lease. A loss of $3,978 related to settlement of this indemnification provision was recognized in Transaction and integration costs in the consolidated statements of operations and comprehensive income (loss) in the second quarter of 2021.

The Company’s results of operations for the year ended December 31, 2021 include GMLP’s result of operations from the date of acquisition, April 15, 2021, through December 31, 2021. Revenue and net income attributable to GMLP during this period was $191,437 and $111,679, respectively.

Acquisition costs associated with the Mergers of $33,907 for the year ended December 31, 2021 were included in Transaction and integration costs in the Company’s consolidated statements of operations and comprehensive income (loss).

Unaudited pro forma financial information

The following table summarizes the unaudited pro forma condensed financial information of the Company as if the Mergers had occurred on January 1, 2020.


 
Year Ended December 31,
 
   
2021
   
2020
 
Revenue
 
$
1,429,361
   
$
813,079
 
Net income (loss)
   
75,415
     
(339,909
)
Net income (loss) attributable to stockholders
   
62,059
     
(264,075
)

The unaudited pro forma financial information is based on historical results of operations as if the acquisitions had occurred on January 1, 2020, adjusted for transaction costs incurred, adjustments to depreciation expense associated with the recognition of the fair value of vessels acquired, additional amortization expense associated with the recognition of the fair value of favorable and unfavorable customer contracts for vessel charters, additional interest expense as a result of incurring new debt and extinguishing historical debt, elimination of a pre-existing lease relationship between the Company and GMLP, and a step-up of the equity method investments.

Pro forma net income (loss) for the year ended December 31, 2020 includes non-recurring expenses associated with the Mergers of $37,885; such non-recurring expenses have been removed from the pro forma financial information for the year ended December 31, 2021. Transaction costs incurred and the elimination of a pre-existing lease relationship between the Company and GMLP are considered to be non-recurring. The unaudited pro forma financial information does not give effect to any synergies, operating efficiencies or cost savings that may result from the Mergers.

GLNG management and services agreements

In connection with the closing of the Mergers, the Company entered into multiple agreements with Golar Management Limited, a subsidiary of GLNG (“Golar Management”), including omnibus agreements, transition services agreements, ship management agreements and other services agreements described as follows:


The Company and Golar Management entered into transition service agreements whereby Golar Management provides certain administrative and consulting services to facilitate the integration of GMLP and Hygo (the “Transition Services Agreements”). The Transition Services Agreements commenced on April 15, 2021, and will terminate on April 30, 2022 unless terminated earlier by either party. The Company pays Golar Management monthly payments of $329 and will reimburse Golar Management for all reasonable and documented out-of-pocket expenses or remittances of funds paid to a third party in connection with the provision of the Transition Services.


The Company’s vessel-owning subsidiaries entered into ship management agreements with Golar Management (the “Ship Management Agreements”), pursuant to which Golar Management provides certain technical, crew, insurance and commercial management services for the acquired vessels for a specified annual cost per vessel. The Ship Management Agreements commenced on April 15, 2021, will continue until terminated by either party by notice, in which event the relevant Ship Management Agreements will terminate upon the later of 12 months after April 15, 2021 or two months from the date on which such notice is received.


The Company also entered into certain agreements to facilitate the integration of the acquired businesses and their operations whereby GLNG or its subsidiaries will continue to provide certain guarantees and indemnities under charter arrangements or GMLP’s and Hygo’s sale leaseback agreements. NFE pays the relevant Charter Guarantor or Golar an annual guarantee fee of $250 per vessel.


The Company and Golar Management (Bermuda) Limited (“Golar Bermuda”) entered into a services agreement (the “Bermuda Services Agreement”) pursuant to which Golar Bermuda will act as GMLP’s and Hygo’s registered office in Bermuda and provide certain corporate secretarial, registrar and administration services (the “Bermuda Services Agreements”). The Bermuda Services Agreements commenced on April 15, 2021. Either party may terminate the Bermuda Services Agreements upon 30 days’ prior written notice. The Company pays Golar Bermuda an aggregate annual fee of $300 for the Bermuda services and will reimburse Golar Bermuda for all incidental documented costs and expenses reasonably incurred by Golar Bermuda and its designees in connection with the provision of the Bermuda services.

During the period subsequent to the completion of the Mergers, the Company incurred $10,881 for the year ended December 31, 2021 in management, services or guarantee fees under these agreements with GLNG, Golar Management or GLNG affiliated entities.

Asset acquisitions

On January 12, 2021, the Company acquired 100% of the outstanding shares of CH4 Energia Ltda. (“CH4”), an entity that owns key permits and authorizations to develop an LNG terminal and an up to 1.37GW gas-fired power plant at the Port of Suape in Brazil. The purchase consideration consisted of $903 of cash paid at closing in addition to potential future payments contingent on achieving certain construction milestones of up to approximately $3,600. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $3,047 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the consolidated balance sheets. The selling shareholders of CH4 may also receive future payments based on gas consumed by the power plant or sold to customers from the LNG terminal. For the year ended December 31, 2021, the Company recognized a gain from the change in fair value of the derivative liability of $31, which is presented in Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss).

The purchase of CH4 has been accounted for as an asset acquisition. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $295 were included in the purchase consideration. The total purchase consideration of $5,776, which includes a deferred tax liability of $1,531 recognized as a result from the acquisition, was allocated to permits and authorizations acquired and was recorded within Intangible assets, net.

On March 11, 2021, the Company acquired 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold grants to operate as an independent power provider and 15-year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil. The Company is seeking to obtain the necessary approvals to transfer the power purchase agreements in connection with the construction the gas-fired power plant and LNG import terminal at the Port of Suape.

The purchase consideration consisted of $8,041 of cash paid at closing in addition to potential future payments contingent on achieving commercial operations of the gas-fired power plant at the Port of Suape of up to approximately $10.5 million. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments as of the acquisition date of $7,473 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the consolidated balance sheets. The selling shareholders may also receive future payments based on power generated by the power plant in Suape, subject to a maximum payment of approximately $4.6 million. For the year ended December 31, 2021, the Company recognized a gain from the change in fair value of the derivative liability of $752, which is presented in Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss).

The purchases of Pecém and Muricy were accounted for as asset acquisitions. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $1,275 were included in the purchase consideration. Of the total purchase consideration, $16,585 was allocated to acquired power purchase agreements and recorded in Intangible assets, net on the consolidated balance sheets; the remaining purchase consideration was related to working capital acquired.

5.
VIEs



Lessor VIEs



The Company assumed sale leaseback arrangements for four vessels as part of the Mergers. The counterparty to each of these sale leaseback arrangements is a VIE, and these lessor VIEs are SPVs wholly owned by financial institutions. While the Company does not hold an equity investment in these entities, these lessor VIEs are consolidated in the consolidated financial statements, and all equity attributable to these lessor VIEs is included in non-controlling interest in the consolidated financial statements. Transactions between our wholly-owned subsidiaries and these VIEs are eliminated in consolidation, including sale leaseback transactions.



CCB Financial Leasing Corporation Limited (“CCBFL”)



In September 2018, the Nanook was sold to a subsidiary of CCBFL, Compass Shipping 23 Corporation Limited, and subsequently leased back on a bareboat charter for a term of twelve years. The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve-year lease period.



Oriental Shipping Company (“COSCO”)



In December 2019, the Penguin was sold to a subsidiary of COSCO, Oriental Fleet LNG 02 Limited, and subsequently leased back on a bareboat charter for a term of six years. The Company has options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six-year lease period.



AVIC International Leasing Company Limited (“AVIC”)



In March 2020, the Celsius was sold to a subsidiary of AVIC, Noble Celsius Shipping Limited, and subsequently leased back on a bareboat charter for a term of seven years. The Company has options to repurchase the vessel throughout the charter term at fixed predetermined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the seven-year lease period.



China Merchants Bank Lending (“CMBL”)



In November 2015, the Eskimo was sold to a subsidiary of CMBL, Sea 23 Leasing Co. Limited (“Eskimo SPV”), and subsequently leased back under a bareboat charter for a term of ten years. The Company had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the ten-year lease period.



In November 2021, the Company exercised its option to repurchase the Eskimo for a total payment of $190,518. After exercising the repurchase option, the Company no longer has a controlling financial interest in the Eskimo SPV, and therefore, upon closing of the repurchase option, the Company deconsolidated the Eskimo SPV from its financial results.  The Company has recognized a loss of $10,975 from exiting this financing arrangement in loss on extinguishment of debt, net in the consolidated statements of operations and comprehensive income (loss).



While the Company does not hold an equity investment in the above SPVs, the Company has a variable interest in these SPVs. The Company is the primary beneficiary of these VIEs and, accordingly, these VIEs are consolidated into the Company’s financial results for the period after the Mergers. The effect of the bareboat charter arrangements is eliminated upon consolidation of the SPVs. The equity attributable to CCBFL, COSCO, AVIC and prior to the repurchase, CMBL, in their respective VIEs is included in non-controlling interests in the consolidated financial statements. As of December 31, 2021, the Penguin and Celsius was recorded in Property, plant and equipment, net on the consolidated balance sheet, and the Nanook was recognized in Finance leases, net on the consolidated balance sheet.



The following table gives a summary of the sale and leaseback arrangements, including repurchase options and obligations as of December 31, 2021:


Vessel
 End of lease term
 Date of next
repurchase option
 
Repurchase price at next repurchase option date
   
Repurchase obligation at end of lease term
 
Nanook
September 2030
March 2022
 
$
199,099
   
$
94,179
 
Penguin
December 2025
December 2022
   
84,668
     
63,040
 
Celsius
March 2027
March 2022
   
98,290
     
45,000
 



A summary of payment obligations under the bareboat charters with the lessor VIEs as of December 31, 2021, are shown below:


Vessel
 
2022
   
2023
   
2024
   
2025
   
2026
     
2027
+
Nanook
 
$
21,810
   
$
21,197
   
$
20,608
   
$
19,971
   
$
19,358
   
$
67,153
 
Penguin
   
12,003
     
11,635
     
11,245
     
8,196
     
-
     
-
 
Celsius
   
15,847
     
15,265
     
14,695
     
14,102
     
12,868
     
-
 



The payment obligation table above includes variable rental payments due under the lease based on an assumed LIBOR plus margin but excludes the repurchase obligation at the end of lease term.



The assets and liabilities of these lessor VIEs that most significantly impact the consolidated balance sheet as of December 31, 2021 are as follows:


   
Nanook
   
Penguin
   
Celsius
 
Assets
                 
Restricted cash
 
$
4,772
   
$
5,563
   
$
25,316
 
Liabilities
                       
Long-term interest bearing debt - current portion
 
$
-
   
$
18,798
   
$
5,799
 
Long-term interest bearing debt - non-current portion
   
186,638
     
71,237
     
107,474
 



As a result of the Mergers, the most significant impact of the lessor VIEs operations on the Company’s consolidated statement of operations is an addition to interest expense of $11,766 for the year ended December 31, 2021. Upon assumption of the debt held by VIEs in conjunction with the Mergers, the Company recognized the liabilities assumed at fair value, and the amortization of the discount of $2,465 has been recognized as an addition to interest expense incurred of $9,301 for the year ended December 31, 2021. The most significant impact of the lessor VIEs cash flows on the consolidated statements of cash flows is net cash used in financing activities of $236,916 for the period subsequent to the completion of the Mergers.



Other VIEs



Hilli LLC



The Company acquired an interest of 50% of the common units of Hilli LLC (“Hilli Common Units”) as part of the acquisition of GMLP. Hilli LLC owns Golar Hilli Corporation (“Hilli Corp”), the disponent owner of the Hilli. The Company determined that Hilli LLC is a VIE, and the Company is not the primary beneficiary of Hilli LLC. Thus, Hilli LLC has not been consolidated into the financial statements and has been recognized as an equity method investment.



As of December 31, 2021 the maximum exposure as a result of the Company’s ownership in the Hilli LLC is the carrying value of the equity method investment of $366,504 and the outstanding portion of the Hilli Leaseback (defined below) which have been guaranteed by the Company.



PT Golar Indonesia (“PTGI”)



The Company acquired all of the voting stock and controls all of the economic interests in PTGI pursuant to a shareholders’ agreement with the other shareholder of PTGI, PT Pesona Sentra Utama (“PT Pesona”), as part of the acquisition of GMLP. PT Pesona holds the remaining 51% interest in the issued share capital of PTGI and provides agency and local representation services for the Company with respect to NR Satu.  PTGI is the owner and operator of NR Satu. The Company determined that PTGI is a VIE, and the Company is the primary beneficiary of PTGI. Thus, PTGI has been consolidated into the financial statements.



The following table summarizes the balance sheet of PTGI as of December 31, 2021:


Assets
 
December 31,
2021
 
Current assets
       
Cash & cash equivalents
 
$
3,257
 
Receivables, net
   
2,610
 
Total current assets
   
5,867
         
Property, plant and equipment, net
   
178,440
 
Intangible assets, net
   
15,595
 
Other non-current assets, net
   
2,642
 
Total assets
  $
202,544  
         
Liabilities
       
Accounts payable
 
$
16,219
 
Accrued liabilities
    907  
Other current liabilities
   
3,664
 
Total current liabilities
    20,790  
         
Deferred tax liabilities, net
   
2,711
 
Total liabilities
    23,501  
         
Total stockholder’s equity
    179,043  
Total liabilities and stockholder’s equity
  $
202,544  

Trade creditors of PTGI have no recourse to our general credit. PTGI paid no dividends to PT Persona during the period after the Mergers.

6.
Revenue recognition

Operating revenue includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam, and the sale of LNG cargos. Included in operating revenue is revenue from cargo sales of $462,695 for the year ended December 31, 2021; there were no comparable transactions for the year ended December 31, 2020. Other revenue includes revenue for development services as well as interest income from the Company’s finance leases and other revenue. The table below summarizes the balances in Other revenue:

 
 
Year Ended December 31,
 
 
 
2021
   
2020
   
2019
 
Development services revenue
 
$
125,924
   
$
129,753
   
$
27,308
 
Interest income and other revenue
   
35,261
     
3,586
     
16,317
 
Total other revenue
 
$
161,185
   
$
133,339
   
$
43,625
 

Development services revenue recognized in the years ended December 31, 2021, 2020 and 2019 included $114,654, $118,757 and $0, respectively, for the customer’s use of natural gas as part of commissioning their assets.

Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of December 31, 2021 and 2020, receivables related to revenue from contracts with customers totaled $192,533 and $76,431, respectively, and were included in Receivables, net on the consolidated balance sheets, net of current expected credit losses of $164 and $98, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases which are accounted for outside the scope of ASC 606, Revenue from Contracts with Customers, and receivables associated with reimbursable costs.

The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The performance obligations are expected to be satisfied during the next 12 months, and the contract liabilities are classified within Other current liabilities on the consolidated balance sheets. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. The contract liabilities and contract assets balances as of December 31, 2021 and 2020 are detailed below:

 
December 31, 2021
   
December 31, 2020
 
Contract assets, net - current
 
$
7,462
   
$
4,029
 
Contract assets, net - non-current
   
36,757
     
30,434
 
Total contract assets, net
 
$
44,219
   
$
34,463
 
                 
Contract liabilities
 
$
2,951
   
$
8,399
 
                 
Revenue recognized in the year from:
               
Amounts included in contract liabilities at the beginning of the year
 
$
8,028
   
$
6,542
 

Contract assets are presented net of expected credit losses of $442 and $376 as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, contract assets was comprised of $43,839 and $6,821 of unbilled receivables, respectively, that represent unconditional rights to payment only subject to the passage of time.

The Company has recognized costs to fulfill a contract with a significant customer, which primarily consist of expenses required to enhance resources to deliver under the agreement with the customer. As of December 31, 2021, the Company has capitalized $10,981, of which $604 of these costs is presented within Other current assets and $10,377 is presented within Other non-current assets on the consolidated balance sheets. As of December 31, 2020, the Company had capitalized $11,276, of which $588 of these costs was presented within Other current assets and $10,688 was presented within Other non-current assets on the consolidated balance sheets. In the first quarter of 2020, the Company began delivery under the agreement and started recognizing these costs on a straight-line basis over the expected term of the agreement.

Transaction price allocated to remaining performance obligations

Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.

The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements represents the fixed margin multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period:

Period
 
Revenue
 
2022
 
$
480,052
 
2023
   
520,335
 
2024
   
516,660
 
2025
   
507,868
 
2026
   
505,729
 
Thereafter
   
7,997,353
 
Total
 
$
10,527,997
 

For all other sales contracts that have a term exceeding one year, the Company has elected the practical expedient in ASC 606 under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. For these excluded contracts, the sources of variability are (a) the market index prices of natural gas used to price the contracts, and (b) the variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG, natural gas, power or steam. As each unit of LNG, natural gas, power or steam represents a separate performance obligation, future volumes are wholly unsatisfied.


Lessor arrangements



The Company’s vessel charters of LNG carriers and FSRUs can take the form of operating or finance leases. Property, plant and equipment subject to vessel charters accounted for as operating leases is included within Vessels within Note 14. Property, plant and equipment, net. The following is the carrying amount of property, plant and equipment that is leased to customers under operating leases:


   
December 31,
2021
   
December 31,
2020
 
Property, plant and equipment
 
$
1,274,234
   
$
18,394
 
Accumulated depreciation
   
(31,849
)
   
(932
)
Property, plant and equipment, net
 
$
1,242,385
   
$
17,462
 



The components of lease income from vessel operating leases for the year ended December 31, 2021 were as follows:


   
Year Ended
 
   
December 31, 2021
 
Operating lease income
 
$
214,193
 
Variable lease income
   
11,067
 
Total operating lease income
 
$
225,260
 



The Company’s charter of the Nanook to CELSE and certain equipment leases provided in connection with the supply of natural gas or LNG are accounted for as finance leases.



After the completion of the Mergers, the Company recognized interest income of $32,880 for the year ended December 31, 2021 related to the finance lease of the Nanook, which is included within Other revenue in the consolidated statements of operations and comprehensive income (loss).  The Company recognized revenue of $5,549 for the year ended December 31, 2021 related to the operation and services agreement within Vessel charter revenue in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2021, there were outstanding balances due from CELSE of $6,428, of which $4,371 is recognized in Receivables, net and a loan to CELSE of $2,057 is recognized in Prepaid expenses and other current assets, net on the consolidated balance sheets. CELSE is an affiliate due to the equity method investment held in CELSE’s parent, CELSEPAR, and as such, these transactions and balances are related party in nature.



The following table shows the expected future lease payments as of December 31, 2021, for 2022 through 2026 and thereafter:


   
Future cash receipts
 
   
Financing Leases
   
Operating Leases
 
2022
 
$
49,951
   
$
261,108
 
2023
   
50,616
     
144,744
 
2024
   
51,442
     
103,418
 
2025
   
51,876
     
26,022
 
2026
   
52,147
     
-
 
Thereafter
   
1,051,956
     
-
 
Total minimum lease receivable
 
$
1,307,988
   
$
535,292
 
Unguaranteed residual value
   
107,000
         
Gross investment in sales-type lease
 
$
1,414,988
         
Less: Unearned interest income
   
807,057
         
Less: Current expected credit losses
   
1,552
         
Net investment in leased vessel
 
$
606,379
         
                 
Current portion of net investment in leased asset
 
$
3,704
         
Non-current portion of net investment in leased asset
   
602,675
         

7.
Leases, as lessee

The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability.

The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or ROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.

As of December 31, 2021 and 2020, right-of-use assets, current lease liabilities and non-current lease liabilities consisted of the following:

 
 
December 31,
2021
   
December 31,
2020
 
Operating right-of-use assets
 
$
285,751
   
$
141,347
 
Finance right-of-use assets (1)
   
23,912
     
-
 
Total right-of-use assets
 
$
309,663
   
$
141,347
 
 
               
Current lease liabilities:
               
Operating lease liabilities
 
$
43,395
   
$
35,481
 
Finance lease liabilities
   
3,719
     
-
 
Total current lease liabilities
 
$
47,114
   
$
35,481
 
Non-current lease liabilities:
               
Operating lease liabilities
 
$
219,189
   
$
84,323
 
Finance lease liabilities
   
14,871
     
-
 
Total non-current lease liabilities
 
$
234,060
   
$
84,323
 

(1) Finance lease right-of-use assets are recorded net of accumulated amortization of $622 as of December 31, 2021.

For the years ended December 31, 2021 and 2020, the Company’s operating lease cost recorded within the consolidated statements of operations and comprehensive income (loss) were as follows:

   
Year Ended December 31,
 
   
2021
   
2020
 
Fixed lease cost
 
$
41,054
   
$
39,841
 
Variable lease cost
   
1,711
     
2,013
 
Short-term lease cost
   
6,974
     
1,454
 
                 
Lease cost - Cost of sales
 
$
41,147
   
$
36,283
 
Lease cost - Operations and maintenance
   
2,343
     
2,501
 
Lease cost - Selling, general and administrative
   
6,249
     
4,524
 

For the years ended December 31, 2021 and 2020, the Company has capitalized $15,568 and $10,457 of lease costs, respectively, for vessels and port space used during the commissioning of development projects in addition to short-term lease costs for vessels chartered by the Company to bring inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory.

During the year ended December 31, 2019, the Company recognized rental expense for all operating leases of $37,069 related primarily to LNG vessel time charters, office space, a land site lease and marine port berth leases.

Beginning in the second quarter of 2021, leases for ISO tanks and a parcel of land that transfer the ownership in underlying assets to the Company at the end of the lease have commenced, and these leases are treated as finance leases. For the year ended December 31, 2021, the Company recognized interest expense related to finance leases of $409, which is included within Interest expense, net in the consolidated statements of operations and comprehensive income (loss). For the year ended December 31, 2021, the Company recognized amortization of the right-of-use asset related to finance leases of $622, which is included within Depreciation and amortization in the consolidated statements of operations and comprehensive income (loss).

Cash paid for operating leases is reported in operating activities in the consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the years ended December 30, 2021 and 2020:

   
Year Ended December 31,
 
   
2021
   
2020
 
Operating cash outflows for operating lease liabilities
 
$
46,066
   
$
45,934
 
Financing cash outflows for finance lease liabilities
   
2,156
     
-
 
Right-of-use assets obtained in exchange for new operating lease liabilities
   
172,996
     
182,799
 
Right-of-use assets obtained in exchange for new finance lease liabilities
   
24,533
     
-
 

The future payments due under operating and finance leases as of December 31, 2021 are as follows:

   
Operating Leases
   
Financing Leases
 
2022
 
$
62,616
   
$
4,515
 
2023
   
49,481
     
4,362
 
2024
   
43,071
     
4,381
 
2025
   
34,677
     
4,381
 
2026
   
26,710
     
2,625
 
Thereafter
   
182,480
     
1,030
 
Total Lease Payments
 
$
399,035
   
$
21,294
 
Less: effects of discounting
   
136,451
     
2,704
 
Present value of lease liabilities
 
$
262,584
   
$
18,590
 
                 
Current lease liability
 
$
43,395
   
$
3,719
 
Non-current lease liability
   
219,189
     
14,871
 

As of December 31, 2021, the weighted-average remaining lease term for operating leases was 9.3 years and finance leases was 5.1 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of December 31, 2021 and 2020 was 8.7% and 8.3%, respectively. The weighted average discount rate associated with finance leases as of December 31, 2021 is 5.1%.

The Company has executed a lease for an LNG carrier that has not commenced as of December 31, 2021 with noncancelable terms of 7 years and including fixed payments of approximately $198.1 million.

8.
Financial instruments

Interest rate and currency risk management

In connection with the Mergers, the Company has acquired financial instruments that GMLP and Hygo used to reduce the risk associated with fluctuations in interest rates and foreign exchange rates. Interest rate swaps are used to convert floating rate interest obligations to fixed rates, which from an economic perspective hedges the interest rate exposure. The Company also acquired a cross currency interest rate swap to manage interest rate exposure on the Debenture Loan and the foreign exchange rate exposure on the US dollar cash flows from the charter of the Nanook to CELSE that support repayment of the Brazilian Real-denominated Debenture Loan.

The Company does not hold or issue instruments for speculative or trading purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts; however, the Company does not anticipate non-performance by any counterparties.

The following table summarizes the terms of interest rate and cross currency interest rate swaps as of December 31, 2021:

Instrument
 
Notional Amount
(in thousands)
 
Maturity Dates
 
Fixed Interest Rate
   
Forward Foreign Exchange Rate
 
Interest rate swap: Receiving floating, pay fixed
 
$
356,250
 
March 2026
   
2.86%

   
N/A
 
Cross currency interest rate swap - Debenture Loan
 
BRL 
230,100
 
September 2024
   
5.90%

   
5.424
 

The mark-to-market gain or loss on our interest rate and foreign currency swaps that are not designated as hedges for accounting purposes for the period are reported in the consolidated statements of operations and comprehensive income (loss) in Other (income) expense, net.

Fair value

Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:

      •
Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.

      •
Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.

     •
Level 3 – unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.

The valuation techniques that may be used to measure fair value are as follows:

     •
Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

     •
Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.

     •
Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of December 31, 2021 and 2020:


 Fair Value  
December 31, 2021
   
December 31, 2021
   
December 31, 2020
   
December 31, 2020
 
Valuation

 Hierarchy  
Carrying Value
   
Fair Value
   
Carrying Value
   
Fair Value
 
Technique
Non-Derivatives:
                         
                     
Cash and cash equivalents
 Level 1  
$
187,509
   
$
187,509
   
$
601,522
   
$
601,522
 
Market approach
Restricted cash
 Level 1    
76,521
     
76,521
     
27,814
     
27,814
 
Market approach
Investment in equity securities
 Level 1    
11,195
     
11,195
     
256
     
256
 
Market approach
Investment in equity securities
 Level 3    
7,678
     
7,678
     
1,000
     
1,000
 
Market approach
Long-term debt (1)
 Level 2    
3,895,255
     
3,910,425
     
1,250,000
     
1,327,488
 
Market approach
Derivatives:
                                 
                                 
Derivative liability (2) (3)
 Level 3  
$
30,686
   
$
30,686
   
$
10,716
   
$
10,716
 
Income approach
Equity agreement (3) (4)
 Level 3    
18,163
     
18,163
     
22,768
     
22,768
 
Income approach
Interest rate swap liability (5) (6)
 Level 2    
21,929
     
21,929
     
-
     
-
 
Income approach


 (1) Long-term debt is recorded at amortized cost on the consolidated balance sheets, and is presented in the above table on a gross basis and not reflective of the deferred financing costs of $40,125 and $10,439 as of December 31, 2021 and December 31, 2020, respectively.

 (2) Consideration due to the sellers in assets acquistions when certain contingent events occur. The liability associated with the derivative liabilities is recorded within Other current liabilities and Other long-term liabilities on the consolidated balance sheets.

 (3) The Company estimates fair value of the derivative liability and equity agreement using a discounted cash flows method with discount rates based on with similar credit ratings and matching terms to the discount periods as well as a probability of the contingent event occurring.

 (4) To be paid at the earlier of agreed-upon date or the date on which the valid planning permission is received for the facility in development in Shannon, Ireland. The liability associated with the equity agreement is recorded within Other current liabilities on the consolidated balance sheets.

 (5) Interest rate swap liability and cross currency interest rate swap liability is presented within Other current liabilities on the consolidated balance sheets.

 (6) The fair value of certain derivative instruments, including interest rate swaps, is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties.


The Company believes the carrying amounts of cash and cash equivalents, accounts receivable, finance lease receivables and accounts payable approximated their fair value as of December 31, 2021 and 2020 and are classified as Level 1 within the fair value hierarchy.

As part of the Hygo Merger, the Company assumed liabilities of $8,608 for payments due to sellers in asset acquisitions completed prior to the Hygo Merger, and these liabilities are reflected as derivative liabilities. Activity during the year ended December 31, 2021 also included the recognition of additional derivative liabilities from transactions accounted for as asset acquisitions of $10,520 (Note 4). During the years December 31, 2021 and 2020, the Company had no settlements of the equity agreement or derivative liabilities or any transfers in or out of Level 3 in the fair value hierarchy.

The table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy, the derivative liability and equity agreement, as well as the cross currency interest rate swap and the interest rate swap. These adjustments have been recorded within Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss) for the years ended December 31, 2021, 2020 and 2019:


 
Year Ended December 31,
 
   
2021
   
2020
   
2019
 
Investment in equity securities - Fair value adjustment - (Gain) loss
  $ (4,315 )   $ -     $ -  
Derivative Liability/Equity Agreement - Fair value adjustment - (Gain) loss
    (341 )     4,408       121  
Interest rate swap - Fair value adjustment - (Gain) loss
    (3,926 )     -       -  
Cross currency interest rate swap - Fair value adjustment - (Gain) loss
    (1,636 )     -       -  

Under the Company’s interest rate swap, the Company is required to provide cash collateral, and as of December 31, 2021, $12,500 of cash collateral is presented as restricted cash on the consolidated balance sheets.

9.
Restricted cash

As of December 31, 2021 and 2020, restricted cash consisted of the following:

 
 
December 31,
2021
   
December 31,
2020
 
Cash held by lessor VIEs
 
$
35,651
   
$
-
 
Collateral for letters of credit and performance bonds
   
27,614
     
900
 
Collateral for interest rate swaps
   
12,500
     
-
 
Collateral for performance under customer agreements     -       15,000  
Collateral for LNG purchases
    -
      11,664
 
Other restricted cash     756       250  
Total restricted cash
 
$
76,521
   
$
27,814
 
                 
Current restricted cash
 
$
68,561
   
$
12,814
 
Non-current restricted cash
    7,960
      15,000
 

Restricted cash does not include minimum consolidated cash balances of $30,000 required to be maintained as part of the financial covenants for sale and leaseback financings and the Vessel Term Loan Facility that is included in Cash and cash equivalents on the consolidated balance sheets as of December 31, 2021.

10.
Inventory

As of December 31, 2021 and 2020, inventory consisted of the following:

 
 
December 31,
2021
   
December 31,
2020
 
LNG and natural gas inventory
 
$
16,815
   
$
13,986
 
Automotive diesel oil inventory
   
4,789
     
3,986
 
Bunker fuel, materials, supplies and other
   
15,578
     
4,888
 
Total inventory
 
$
37,182
   
$
22,860
 

Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the consolidated statements of operations and comprehensive income (loss). No adjustments were recorded during the years ended December 31, 2021 and 2020. The Company recorded an adjustment to the value of inventory of $251 during the year ended December 31, 2019.

11.
Prepaid expenses and other current assets

As of December 31, 2021 and 2020, prepaid expenses and other current assets consisted of the following:

 
 
December 31,
2021
   
December 30,
2020
 
Prepaid expenses
   
19,951
     
16,928
 
Recoverable taxes
    31,788       7,335  
Due from affiliates
   
3,299
     
1,881
 
Other current assets
   
28,077
     
22,126
 
Total prepaid expenses and other current assets, net
 
$
83,115
   
$
48,270
 

Other current assets as of December 31, 2021 and 2020 primarily consists of receivables for recoverable taxes and deposits.

12.
Equity method investments

As a result of the Mergers, the Company acquired investments in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) and Hilli LLC, both of which have been recognized as equity method investments. The Company has a 50% ownership interest in both entities. The investments are reflected in the Terminals and Infrastructure and Ships segments, respectively.

Changes in the balance of the Company’s equity method investments is as follows:

   
December 31, 2021
 
Equity method investments as of December 31, 2020
 
$
-
 
Acquisition of equity method investments in the Mergers
   
1,179,021
 
Dividends
   
(21,364
)
Equity in earnings / losses of investees
   
14,443
 
Foreign currency translation adjustment
   
9,913
 
Equity method investments as of December 31, 2021
 
$
1,182,013
 

The carrying amount of equity method investments as of December 31, 2021 is as follows:

   
December 31, 2021
 
Hilli LLC
 
$
366,504
 
CELSEPAR
   
815,509
 
Total
 
$
1,182,013
 

As of December 31, 2021, the carrying value of the Company’s equity method investments exceeded its proportionate share of the underlying net assets of its investees by $792,995. In conjunction with the provisional amounts recognized for the Mergers, the basis difference of $750,824 was allocated to tangible assets, identifiable intangible assets, liabilities and goodwill, and the basis difference attributable to amortizable net assets is amortized to Income from equity method investments over the remaining estimated useful lives of the underlying assets.

CELSEPAR

CELSEPAR is jointly owned and operated with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., and the Company accounts for this 50% investment using the equity method. CELSEPAR owns 100% of the share capital of Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of the Sergipe Power Plant.

The following table summarizes the financial information of CELSEPAR shown on a 100% basis as of December 31, 2021 and the period subsequent to the Mergers:

   
December 31, 2021
 
Balance sheet
     
Current assets
 
$
314,811
 
Non-current assets
   
1,651,569
 
Current liabilities
   
366,530
 
Non-current liabilities
   
1,422,147
 
         
Statement of operations
       
Revenues
 
$
596,852
 
Net loss
   
(9,911
)

Hilli LLC

The Company acquired an interest of 50% of the Hilli Common Units as part of the acquisition of GMLP.  The ownership interests in Hilli LLC are represented by three classes of units, Hilli Common Units, Series A Special Units and Series B Special Units. The Company did not acquire any of the Series A Special Units or Series B Special Units. The Hilli Common Units provide the Company with significant influence over Hilli LLC. The Hilli is currently operating under an 8-year liquefaction tolling agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures.

Within 60 days after the end of each quarter, GLNG, the managing member of Hilli LLC, shall determine the amount of Hilli LLC’s available cash and appropriate reserves, and Hilli LLC shall make a distribution to the unitholders of Hilli LLC (“Hilli Unitholders”) of the available cash, subject to such reserves. Hilli LLC shall make distributions to the Hilli Unitholders when, as and if declared by GLNG; provided, however, that no distributions may be made on the Hilli Common Units on any distribution date unless Series A Distributions and Series B Distributions for the most recently ended quarter and any accumulated Series A Distributions and Series B Distributions in arrears for any past quarter have been or contemporaneously are being paid or provided for.

Series A Distributions are calculated based on cash received by Hilli Corp for any tolling fees under the LTA relating to an increase in the Brent Crude price above $60 per barrel, adjusted by incremental taxes and costs that arise from underperformance of the Hilli. Series B Distributions are calculated as 95% of “Revenues Less Expenses”, which is based on the cash receipts as a direct result of the employment of more than the first 50% of LNG production capacity for the Hilli, adjusted for incremental operating expenses, capital costs, financing and tax costs associated with making more than 50% capacity available and costs that arise from underperformance. The Hilli Common Units may receive 5% of Revenues less Expenses received by Hilli Corp during such quarter.

The Company is required to reimburse other investors in Hilli LLC for 50% of the amount, if any, by which certain operating expenses and withholding taxes of Hilli LLC are below an annual threshold for up to $20,000 in the aggregate through 2026. Other investors are required to reimburse the Company for 50% of the amount, if any, by which certain operating expenses and withholding taxes are above an annual threshold for up to $20,000 in the aggregate through 2026. Operating expense reimbursements did not materially impact the results of operations for the period after the GMLP Merger.

Hilli Corp is a party to a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). The Hilli Leaseback provided for postconstruction financing for the Hilli in the amount of $960 million. Under the Hilli Leaseback, Hilli Corp will pay to Fortune forty consecutive equal quarterly repayments of 1.375% of the construction cost, plus interest based on LIBOR plus a margin of 4.15%.

The following table summarizes the financial information of Hilli LLC shown on a 100% basis as of December 31, 2021 and the period subsequent to the Mergers:

   
December 31, 2021
 
Balance sheet
     
Current assets
 
$
68,435
 
Non-current assets
   
1,359,795
 
Current liabilities
   
61,595
 
Non-current liabilities
   
766,302
 
         
Statement of operations
       
Revenues
 
$
157,550
 
Net income
   
310,006
 

During the period subsequent to the completion of the Mergers, net income for the year ended December 31, 2021 significantly exceeded total revenues for Hilli LLC as a result of the unrealized mark-to market movement in the oil derivative asset associated to the fair value of the Brent Crude price. The unrealized mark-to market movement in the oil derivative asset is allocated to the Series A Special unitholders only; as the Company does not own any of the Series A Special Units, gains and losses from income attributable to these units are not reflected in the Company’s income from equity method investments.

13.
Construction in progress

The Company’s construction in progress activity during the years ended December 31, 2021 and 2020 is detailed below:

 
 
December 31,
2021
   
December 31,
2020
 
Balance at beginning of period
 
$
234,037
   
$
466,587
 
Acquisition of construction in progress from business combinations
    128,625       -  
Additions
   
790,395
     
118,530
 
Impact of change in FX rates
    (6,428 )     -  
Transferred to property, plant and equipment, net or finance leases
   
(102,746
)
   
(351,080
)
Balance at end of period
 
$
1,043,883
   
$
234,037
 

Interest expense of $30,093, $25,924 and $25,172, inclusive of amortized debt issuance costs, was capitalized for the years ended December 31, 2021, 2020 and 2019, respectively.

The Company’s development activities are primarily in Latin America as of December 31, 2021, and the completion of such development is subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.

14.
Property, plant and equipment, net
 
As of December 31, 2021 and 2020, the Company’s property, plant and equipment, net consisted of the following:

 
 
December 31,
2021
   
December 31,
2020
 
Vessels
  $ 1,461,211     $ -  
Terminal and power plant equipment
 

206,889
   

188,855
 
CHP facilities
   
122,777
     
119,723
 
Gas terminals
   
167,614
     
120,810
 
ISO containers and other equipment
   
134,775
     
100,137
 
LNG liquefaction facilities
   
63,213
     
63,213
 
Gas pipelines
   
58,987
     
58,974
 
Land
   
55,008
     
16,246
 
Leasehold improvements
   
9,377
     
8,723
 
Accumulated depreciation
   
(141,915
)
   
(62,475
)
Total property, plant and equipment, net
 
$
2,137,936
   
$
614,206
 

Depreciation for the years ended December 31, 2021, 2020 and 2019 totaled $80,220, $32,116 and $7,527, respectively, of which $1,167, $927 and $701, respectively, is included within Cost of sales in the consolidated statements of operations and comprehensive income (loss).

Capitalized drydocking costs of $8,087 are included in the vessel cost for December 31, 2021 which are depreciated from the completion of drydocking until the next expected dry docking.

15.
Goodwill and intangible assets


Goodwill



The following table summarizes the changes in the carrying amount of goodwill as of December 31, 2021 and 2020:


   
Terminals and
Infrastructure
 
Balance at December 31, 2020
  $
-
 
Acquired in the Mergers
   
760,135
 
Balance at December 31, 2021
  $
760,135
 



The Company performed its annual goodwill impairment test as of October 1, 2021 and conducted a qualitative assessment. The Company concluded that it was not more likely than not that the fair value of each reporting unit was less than the carrying amount, and no goodwill impairment charges were recognized during the year ended December 31, 2021.



Intangible assets

The following tables summarize the composition of intangible assets as of December 31, 2021 and 2020:

 
 
December 31, 2021
 
 
 
Gross Carrying
Amount
   
Accumulated
Amortization
   
Currency Translation Adjustment
   
Net Carrying
Amount
   
Weighted
Average Life
 
Definite-lived intangible assets
                             
Favorable vessel charter contracts
 
$
106,500
   
$
(27,074
)
  $ -    
$
79,426
     
3
 
Permits and development rights
    48,217       (3,311 )     (119 )     44,787       38  
Acquired power purchase agreements
    16,585       (750 )     406       16,241       17  
Easements
   
1,556
     
(243
)
    -
     
1,313
     
30
 
 
                                       
Indefinite-lived intangible assets
                                       
Easements
   
1,191
     
-
      (14 )    
1,177
     
n/a
 
Total intangible assets
 
$
174,049
   
$
(31,378
)
  $ 273    
$
142,944
         

 
 
December 31, 2020
 
 
 
Gross Carrying
Amount
   
Accumulated
Amortization
   
Currency Translation
Adjustment
   
Net Carrying
Amount
   
Weighted
Average Life
 
Definite-lived intangible assets
                             
Permits
 
$
42,441
   
$
(2,438
)
  $ 3,456    
$
43,459
     
40
 
Easements
   
1,559
     
(190
)
    -      
1,369
     
30
 
                                         
Indefinite-lived intangible assets
                                       
Easements
   
1,191
     
-
      83      
1,274
     
n/a
 
Total intangible assets
 
$
45,191
   
$
(2,628
)
  $ 3,539    
$
46,102
         


In conjunction with the Mergers, the Company acquired charter contracts with contractual rates that were favorable as compared to market rates and on the date of acquisition recognized intangible assets of $106,500. During the first quarter of 2021, the Company recognized additions to permits of $5,776 acquired in a transaction accounted for as asset acquisition related to licenses and rights to develop a gas-fired power plant and associated infrastructure in the Port of Suape in Brazil. The Company also acquired rights operated a power generation facility and sell power in Brazil of $16,585 (see Note 4. Acquisitions).



As of December 31, 2021 and 2020, the weighted-average remaining amortization periods for the intangible assets were 14.7 years and 37.5 years, respectively. Amortization expense for the year ended December 31, 2021 totaled $18,609, which is inclusive of reductions in expense for the amortization of unfavorable contract liabilities assumed in the Mergers. Amortization expense for the years ended December 31, 2020 and 2019 totaled $1,120 and $1,114, respectively.



The estimated aggregate amortization expense, inclusive of reductions in expense for the amortization of unfavorable contract liabilities assumed in the Mergers, for each of the next five years is:



Year ended December 31:
     
2022
 
$
37,434
 
2023
   
25,979
 
2024
   
17,409
 
2025
   
4,591
 
2026
   
2,335
 
Thereafter
   
51,086
 
Total
 
$
138,834
 

16.
Other non-current assets

As of December 31, 2021 and 2020, Other non-current assets consisted of the following:

 
 
December 31,
2021
   
December 31,
2020
 
Deposits
 
$
2,400
   
$
28,509
 
Contract asset, net (Note 6)
   
36,757
     
30,434
 
Investments in equity securities     18,873       1,256  
Cost to fulfill (Note 6)
   
10,377
     
10,688
 
Upfront payments to customers
   
9,748
     
6,330
 
Other
   
20,263
     
8,813
 
Total other non-current assets
 
$
98,418
   
$
86,030
 

Deposits as of December 31, 2020 are primarily related to deposits for land purchases in Ireland that we completed in 2021.

Upfront payments to customers consist of amounts the Company has paid in relation to two natural gas sales contracts with customers to construct fuel-delivery infrastructure that the customers will own.

The Company recognized unrealized gains (losses) on its investments in equity securities of $8,254, $(2,284) and $(1,116) for the year ended December 31, 2021, 2020 and 2019, respectively within Other (income), net in the consolidated statements of operations and comprehensive income (loss).

Other includes upfront payments to our service providers and financing costs associated with the Revolving Facility.

17.
Accrued liabilities

As of December 31, 2021 and 2020, accrued liabilities consisted of the following:

 
December 31,
2021
   
December 31,
2020
 
Accrued development costs
 
$
101,177
   
$
16,631
 
Accrued interest
   
61,630
     
27,938
 
Accrued bonuses
   
27,591
     
17,344
 
Accrued vessel operating and drydocking expenses     12,767       -  
Accrued consideration in asset acquisition     9,330       -  
Other accrued expenses
   
31,530
     
28,439
 
Total accrued liabilities
 
$
244,025
   
$
90,352
 


18.
Other current liabilities



As of December 31, 2021 and 2020, other current liabilities consisted of the following:


   
December 31,
2021
   
December 31,
2020
 
Deferred revenue
 
$
28,662
   
$
7,120
 
Interest rate swaps (Note 8)
   
21,929
     
-
 
Equity agreement (Note 8)
   
18,163
     
22,768
 
Income tax payable
   
8,881
     
2,046
 
Due to affiliates
   
9,088
     
8,980
 
Other current liabilities
   
19,313
     
3,072
 
Total other current liabilities
 
$
106,036
   
$
43,986
 



Deferred revenue includes contract liabilities and prepayments received from lessees under charter agreements. Other primarily consists of the value of unfavorable contracts assumed  in the Mergers.

19.
Debt

As of December 31, 2021 and 2020, debt consisted of the following:

   
December 31, 2021
   
December 31, 2020
 
Senior Secured Notes, due September 2025
  $
1,241,196
     $
1,239,561
 
Senior Secured Notes, due September 2026
   
1,477,512
     
-
 
Vessel Term Loan Facility, due September 2024
   
408,991
     
-
 
Debenture Loan, due September 2024
   
40,665
     
-
 
CHP Facility
   
96,820
     
-
 
Revolving Facility
   
200,000
     
-
 
Subtotal (excluding lessor VIE loans)
   
3,465,184
     
1,239,561
 
CCBFL VIE loan:
               
Golar Nanook SPV facility, due September 2030
   
186,638
     
-
 
COSCO VIE loan:
               
Golar Penguin SPV facility, due December 2025
   
90,035
     
-
 
AVIC VIE loan:
               
Golar Celsius SPV facility, due September 2023/ May 2027
   
113,273
     
-
 
Total debt
  $
3,855,130
    $
1,239,561
 
Current portion of long-term debt
  $
97,251
    $
-
 
Long-term debt
   
3,757,879
     
1,239,561
 

Our outstanding debt as of December 31, 2021 is repayable as follows:

   
December 31, 2021
 
2022
  $
87,849
 
2023
   
133,052
 
2024
   
323,097
 
2025
   
1,318,381
 
2026
   
1,709,874
 
Thereafter
   
323,902
 
Total debt
  $
3,896,155
 
Less: fair value adjustments to assumed debt obligations
   
(900
)
Less: deferred finance charges
   
(40,125
)
Total debt, net deferred finance charges
  $
3,855,130
 

2025 Notes

In September 2020, the Company 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 on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. The Company 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 the Company’s subsidiaries, in addition to other collateral. The 2025 Notes may limit the Company’s 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.

The Company 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, the Company 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 previous 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, the Company recognized $4,028 of third-party fees as an expense in the consolidated statements of operations and comprehensive loss.

In December 2020, the Company 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 of December 31, 2021 and 2020, remaining unamortized deferred financing costs for the 2025 Notes were $8,804 and $10,439, respectively.

2026 Notes

In April 2021, the Company 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 on March 31 and September 30 of each year, commencing on September 30, 2021; no principal payments are due until maturity on September 30, 2026. The Company 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 the Company’s existing first lien obligations under the 2025 Notes.

The Company used the net proceeds from this offering to fund the cash consideration for the Mergers and pay related fees and expenses.

In connection with the issuance of the 2026 Notes, the Company 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 of December 31, 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $22,488.

Vessel Term Loan Facility

In September 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 percent. The Vessel Term Loan Facility shall be repaid in quarterly installments of $15,357, with the final repayment date in September 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.  As of December 31, 2021, the aggregate net book value of the three floating storage and regasification vessels and four liquified natural gas carriers pledged as security was approximately $660,567.

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 that GMLP 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 Consolidated Net Worth is greater than $250,000, each as defined in the Vessel Term Loan Facility. The Company was in compliance with these covenants as of December 31, 2021.

In connection with the closing the Vessel Term Loan Facility, the Company incurred $6,324 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the Vessel Term Loan Facility on the consolidated balance sheets. As of December 31, 2021, total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was $5,652.

Debenture Loan

As part of the Hygo Merger, the Company assumed non-convertible Brazilian debentures issued by NFE Brasil, an indirect subsidiary of Hygo, in the aggregate principal amount of BRL 255.6 million ($45.0 million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debenture Loan”). The Debenture Loan was recognized at fair value of $44,566 on the date of the Hygo Merger, 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 on September 13 and March 13.

The Debenture Loan is fully and unconditionally guaranteed by 100% of the shares issued by NFE Brasil owned by the Company’s consolidated subsidiary, LNG Power Ltd.

CHP Facility

In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100,000. The CHP Facility was secured by a mortgage over the lease of the site on which the Company’s combined heat and power plant in Clarendon, Jamaica (“CHP Plant”) and related security. The Company incurred $3,243 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the CHP Facility on the consolidated balance sheets. As of December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $3,180.

Subsequent to December 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 in CHP Senior Secured 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 the South Power 2029 Bonds. In February 2022, the Company issued $59,730 of South 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 in May 2025, principal payments will be due on a quarterly basis. Interest payments on outstanding principal balances will be due quarterly.

South Power will 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

In April 2021, the Company 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 the Company to extend the maturity date once in a one-year increment.

Borrowings under the Revolving Facility will 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 the option of the Company, at any time without premium.

The obligations under the Revolving Facility are guaranteed by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially the same collateral as the Company’s 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 ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 (each as defined in the Revolving Facility).  The Company was in compliance with these covenants as of December 31, 2021.

The Company 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 of December 31, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $3,807. As of December 31, 2021, the full capacity of the Revolving Facility has been drawn and $200,000 remains outstanding.

Lessor VIE debt

The Company assumed the following loans in the Mergers related to lessor VIE entities, including CMBL, CCBFL, COSCO and AVIC, that are consolidated as VIEs. Although the Company has no control over the funding arrangements of these entities, the Company is the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the consolidated financial statements.

CCBFL – Nanook SPV facility

The SPV, Compass Shipping 23 Corporation Limited, the owner of the Nanook, has a long-term loan facility due to its parent that is denominated in USD, which matures in September 2030 and bears interest at a fixed rate of 2.5% as of December 31, 2021. As of the acquisition date of Hygo, the outstanding principal balance was $202,249, and the Company recognized the fair value of this facility of $201,484 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity.

COSCO – Penguin SPV facility

The SPV, 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 in December 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 of Hygo, the outstanding principal balance was $104,882, and the Company 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.

AVIC – Celsius SPV facility

The SPV, Noble Celsius Shipping Limited, the owner of the Celsius, has two long-term loan facilities that are denominated in USD.  The first facility is repayable in quarterly installments over a term of approximately seven years with a balloon payment of $37,179 due upon maturity in May 2027 and bears interest at LIBOR plus a margin of 1.8%; the outstanding principal balance as of the acquisition date of this facility was $76,179.  The SPV has another facility with its parent for the remaining principal of $45,200 as of the acquisition date, which is due as a balloon payment upon maturity in March 2023 and bears interest at a fixed rate of 4.0%. As of the acquisition date of Hygo, the total outstanding principal balance was $121,379, and the Company recognized the fair value of $121,308 on the date of the Mergers. The discount recognized in purchase accounting will be recognized as additional interest expense until maturity.

CMBL – Eskimo SPV facility

The Eskimo SPV, the owner of the Eskimo, had a long-term loan facility that was denominated in USD, had a loan term of ten years and bore interest at a rate of LIBOR plus a margin of 2.66%. As of the acquisition date of GMLP, the outstanding principal balance was $160,520, and the Company recognized the fair value of this facility of $158,072 on the date of the Mergers. The discount recognized in purchase accounting was recognized as additional interest expense until the deconsolidation of the Eskimo SPV.

In November 2021, the Company exercised its option to repurchase the Eskimo for a total payment of $190,518. After exercising the repurchase option, the Company no longer has a controlling financial interest in the Eskimo SPV and no longer recognizes the Eskimo SPV facility in the consolidated financial statements. The Company has recognized a loss of $10,975 from exiting this financing arrangement in loss on extinguishment of debt, net in the consolidated statements of operations and comprehensive income (loss).

Debt and lease restrictions

The VIE loans and certain lease agreements with customers 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.

Interest Expense

Interest and related amortization of debt issuance costs, premiums and discounts recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the years ended December 31, 2021, 2020 and 2019 consisted of the following:

   
Year Ended December 31,
 
   
2021
   
2020
   
2019
 
Interest per contractual rates
  $
175,420
    $
76,176
    $
32,283
 
Amortization of fair value adjustments to assumed debt obligations
   
2,569
     
-
     
-
 
Amortization of debt issuance costs, premiums and discounts
   
6,019
     
15,471
     
12,301
 
Interest expense incurred on finance lease obligations
   
409
     
-
     
-
 
Total interest costs
  $
184,417
    $
91,647
    $
44,584
 
Capitalized interest
   
30,093
     
25,924
     
25,172
 
Total interest expense
  $
154,324
    $
65,723
    $
19,412
 

20.
Income taxes

The components of the Company’s income (loss) before income taxes for the years ended December 31, 2021, 2020 and 2019 were as follows:

   
Year Ended December 31,
 
 
 
2021
   
2020
   
2019
 
United States
 
$
(283,363
)
 
$
(166,571
)
 
$
(194,481
)
Foreign
   
388,535
     
(92,577
)
   
(9,399
)
Income (loss) before taxes
 
$
105,172
   
$
(259,148
)
 
$
(203,880
)

Income tax expense is comprised of the following for the years ended December 31, 2021, 2020 and 2019:

   
Year Ended December 31,
 
   
2021
   
2020
   
2019
 
Current:
                 
Domestic
 
$
311
   
$
-
   
$
-
 
Foreign
   
20,975
     
2,063
     
47
 
Total current tax expense
   
21,286
     
2,063
     
47
 
Deferred:
                       
Domestic
   
-
     
-
     
-
 
Foreign
   
(8,825
)
   
2,754
     
392
 
Total deferred tax expenses (benefit)
   
(8,825
)
   
2,754
     
392
 
Total provision for (benefit from) income taxes
 
$
12,461
   
$
4,817
   
$
439
 

Effective Tax Rate

A reconciliation of the U.S. federal statutory income tax rate to the Company’s effective tax rate is as follows:

   
Year Ended December 31,
 
   
2021
   
2020
   
2019
 
Income tax at the statutory rate
   
21.0
%
   
21.0
%
   
21.0
%
Foreign tax rate differential
   
(32.3
)
   
2.9
   
8.7
US taxation on foreign earnings
   
9.6
   
(2.9
)
   
-
Change in valuation allowance
   
14.7
   
(14.1
)
   
(12.9
)
Income attributable to non-controlling interest
   
0.8
   
(6.4
)
   
(18.2
)
Effects of share based compensation
   
(8.5
)
   
-
   
-
Withholding taxes
   
9.5
   
-
   
-
Income tax credits
   
(2.4
)
   
-
   
-
Other
   
(0.6
)
   
(2.4
)
   
1.2
Effective income tax rate
   
11.8
%
   
(1.9
%)
   
(0.2
%)

As a result of the Mergers, the Company acquired certain operations in jurisdictions that are not subject to income taxes. The effect of these earnings taxed at zero percent, as well as the impact of preferential tax rates are included in the foreign rate differential.

The tax effect of each type of temporary difference and carryforward that give rise to a significant deferred tax asset or liability as of December 31, 2021 and 2020 are as follows:

   
Year Ended December 31,
 
   
2021
   
2020
 
Deferred tax assets:
           
Outside basis difference in partnership
 
$
-
   
$
64,553
 
Accrued interest
   
26,408
     
18,885
 
IRC Section 163(j) interest carryforward
   
21,782
     
6,909
 
Federal and state net operating loss carryforward
   
19,061
     
32,145
 
Foreign net operating loss carryforward
   
43,735
     
24,525
 
Lease liability
   
60,967
     
4,383
 
Goodwill
   
55,394
     
-
 
Other
   
26,547
     
7,863
 
Total deferred tax assets
   
253,894
     
159,263
 
Valuation allowance
   
(146,269
)
   
(132,497
)
Deferred tax assets, net of valuation allowance
   
107,625
     
26,766
 
                 
Deferred tax liabilities:
               
Equity method investments
   
(252,224
)
   
-
 
Property and equipment
   
(47,205
)
   
(22,566
)
Lease asset
   
(62,403
)
   
(4,215
)
Other
   
(9,307
)
   
-
 
Total deferred tax liabilities
 
$
(371,139
)
 
$
(26,781
)
Net deferred tax liabilities
 
$
(263,514
)
 
$
(15
)

As of December 31, 2020, the Company effectively held 100% of the interests in a partnership that owned substantially all of the Company’s operations. On January 1, 2021, the partnership interest was contributed to a wholly-owned corporate entity, effectively liquidating the partnership for federal and state income tax purposes. Prior to the liquidation of the partnership, deferred taxes related to the investment in the partnership were recorded as a single outside basis difference in the Company’s financial statements which represented excess tax basis in the investment over the financial statement carrying value. Subsequent to the liquidation, the Company reports deferred tax assets and liabilities for the tax effect of temporary differences between the tax basis and the financial statement carrying values of each underlying asset and liability of the former partnership including tax basis allocated to goodwill.

As a result of the Mergers, the Company recognized net deferred tax liabilities of $269,856 that reflect the impact of the financial statement fair value adjustments, principally the increased value of equity method investments. The Company acquired tax attribute carryforwards including net operating losses in certain jurisdictions which were recorded and offset with a valuation allowance as a result of cumulative losses and the developmental status of the entities with the exception of net operating losses that are realizable as a result of taxable temporary differences related to an equity method investment.

Tax Attributes

United States

As of December 31, 2021, NFE has approximately $87,073 of federal and $17,915 of state net operating loss carry forwards. The federal and state net operating losses are generally allowed to be carried forward indefinitely and can offset up to 80 percent of future taxable income.

Under the provisions of Internal Revenue Code Section 382, certain substantial changes in the Company’s ownership may result in a limitation on the amount of U.S. net operating loss carryforwards that can be utilized annually to offset future taxable income and taxes payable. A portion of the Company’s net operating loss carryforwards are subject to an annual limitation of $5,431 under Section 382 of the Internal Revenue Code.

Foreign Jurisdictions

The Company’s foreign subsidiaries file income tax returns in certain foreign jurisdictions. As of December 31, 2021, the Company’s foreign subsidiaries have approximately $157,149 of net operating loss carry forwards, of which $24,685 will expire, if unused beginning in 2028, and the remaining are allowed to be carried forward indefinitely.

Valuation Allowances

The following table summarizes the changes in the Company’s valuation allowance on deferred tax assets for the years ended December 31, 2021 and 2020:

   
Year Ended December 31,
 
 
 
2021
   
2020
 
Balance at the beginning of the period
 
$
132,497
   
$
80,911
 
Change in valuation allowance
   
13,772
     
51,586
 
Balance at the end of the period
 
$
146,269
   
$
132,497
 

NFE recorded a valuation allowance against its US federal and state deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized. The US jurisdiction is in a cumulative loss position. As of December 31, 2021, the Company concluded, based on the weight of all available positive and negative evidence, those deferred tax assets are not more likely than not to be realized and accordingly, a valuation allowance has been recorded on this deferred tax asset for the amount not supported by reversing taxable temporary differences.

The Company recorded a valuation allowance against other foreign deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized, generally based on cumulative losses in development stage jurisdictions.

Uncertain Taxes

The following table summarizes the changes in the Company’s unrecognized tax benefits for the years ended December 31, 2021 and 2020:

   
Year Ended December 31,
 
 
 
2021
   
2020
 
Balance at the beginning of the period
 
$
-
   
$
-
 
Assumed in the Mergers
   
12,705
     
-
 
Recognized in the income tax provision
   
(231
)
   
-
 
Balance at the end of the period
 
$
12,474
   
$
-
 

The liability for unrecognized tax benefits is included in Other non-current liabilities on the consolidated balance sheets. The Company accrued $1,371 of interest expense during 2021 and has total interest accrued of $3,667 as of December 31, 2021. During the years ended December 31, 2020 and 2019, the Company did not have any unrecognized tax benefits. The Company does not anticipate a material reversal of unrecognized tax benefits during the next 12 months.

In addition to the liabilities for unrecognized income tax benefits assumed in the Mergers, the Company assumed liabilities related to potential employment tax obligations that are accounted for under ASC 450 of $6,309. This liability is also included in Other non-current liabilities on the consolidated balance sheets as the liabilities are not expected to be settled in the next 12 months.

Income Tax Examinations

The Company and its subsidiaries file income tax returns in the U.S. federal and various state and local jurisdictions, as well as various foreign jurisdictions. As a result of the Mergers, the Company has operations in Jordan and Kuwait that are currently under examination. The examinations in Kuwait relate to the 2017 to 2019 tax years and the examinations in Jordan operations relate to the 2015 to 2017 tax years. The Company does not expect the result of the examinations to have a significant impact on income tax expense. The Company filed its first corporate U.S. federal and state income tax returns for the period ended December 31, 2019.  The U.S. Federal and state income tax returns filed for tax years 2019 and 2020 are open for examination. The Company is generally open to tax examinations in other foreign jurisdictions for a period of four to six years from the filing of the income tax return.

Undistributed Earnings

As of December 31, 2021, the Company has recorded a deferred tax liability for undistributed earnings of its Indonesian controlled foreign corporation of approximately $2,259. The Company has not recorded a deferred tax liability for undistributed earnings of any other controlled foreign corporation as of December 31, 2021. The Company has unremitted earnings in certain jurisdictions where distributions can be made at no net tax cost. From time to time, the Company may remit these earnings.  The Company has the ability and intent to indefinitely reinvest any earnings that cannot be remitted at no net tax cost.  It is not practicable to estimate the amount of any additional taxes which may be payable on these undistributed earnings.

Preferential Tax Rates

The Company has subsidiaries incorporated in Bermuda. Under current Bermuda law, the Company is not required to pay taxes in Bermuda on either income or capital gains. The Company has received an undertaking from the Bermuda government that, in the event of income or capital gain taxes being imposed, it will be exempted from such taxes until 2035.

The Company’s Puerto Rican operations received a tax decree from the Puerto Rico government that affords the Company a 4 percent tax rate on qualifying income until 2035. The effect of the earnings taxed at a 4 percent foreign tax rate is included in the foreign rate differential line in the Company’s effective tax rate. For the years ended December 31, 2021 and 2020, the income tax benefits attributable to the tax decree, before taking into consideration the impact on U.S. taxation and the associated U.S. foreign tax credits, are estimated to be approximately $14,047 ($0.07 per share of issued and outstanding Class A common stock on a diluted basis) and $5,550 ($0.05 per share of issued and outstanding Class A common stock on a diluted basis), respectively.

21.
Commitments and contingencies


Legal proceedings and claims



The Company may be subject to certain legal proceedings, claims and disputes that arise in the ordinary course of business, and the Company has evaluated the contingencies that have been assumed in conjunction with the Mergers. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.



In conjunction with the Mergers, the Company has assumed contingencies for VAT in Indonesia. Indonesian tax authorities have issued letters to PTGI, a consolidated subsidiary, to revoke a previously granted VAT importation waiver for approximately $24,000 for the NR Satu. The Company does not believe it probable that a liability exists as no Tax Underpayment Assessment Notice has been received within the statute of limitations period, and the Company believes PTGI will be indemnified by PT Nusantara Regas, the charterer of the NR Satu, for any VAT liability as well as related interest and penalties under the time charter party agreement.



Prior to the Mergers, Indonesian tax authorities also issued tax assessments for land and buildings tax to PTGI for the years 2015 to 2019 in relation to the NR Satu, for approximately $3,392 (IDR 48,344.4 million). The Company intends to appeal against the assessments for the land and buildings tax as the tax authorities have not accepted the initial objection letter. The Company believes there are reasonable grounds for success on the basis of no precedent set from past case law and the new legislation effective prospectively from January 1, 2020, that now specifically lists FSRUs as being an object liable to land and buildings tax, when it previously did not.  The assessed tax was paid in January 2020 to avoid further penalties and the payment is presented in Other non-current assets on the consolidated balance sheets.



Prior to the Mergers, Jordanian tax authorities concluded their tax audit into GMLP’s Jordan branch for the years 2015 and 2016 assessing additional tax of approximately $1,600 (JOD 1.10 million) and $3,100 (JOD 2.20 million), respectively. The Company has submitted an appeal to the tax notice, and a provision has not been recognized as the Company does not believe that the tax inspector has followed the correct tax audit process and the claim by the tax authorities to not allow tax depreciation is contrary to Jordan’s tax legislation.

22.
Earnings per share


 
Year Ended December 31,
 
   
2021
   
2020
   
2019
 
Basic
                 
Numerator:
                 
Net income (loss)
 
$
92,711
   
$
(263,965
)
 
$
(204,319
)
Less: net loss attributable to non-controlling interests
   
4,393
     
81,818
     
170,510
 
Net income (loss) attributable to Class A common stock
 
$
97,104
   
$
(182,147
)
 
$
(33,809
)
                         
Denominator:
                       
Weighted-average shares - basic
   
198,593,042
     
106,654,918
     
20,862,555
 
Net income (loss) per share - basic
 
$
0.49
   
$
(1.71
)
 
$
(1.62
)
                         
Diluted
                       
Numerator:
                       
Net income (loss)
 
$
92,711
   
$
(263,965
)
 
$
(204,319
)
Less: net loss attributable to non-controlling interests
   
4,393
     
81,818
     
170,510
 
Less: adjustments attributable to dilutive securities
   
2,861
     
-
     
-
 
Net income (loss) attributable to Class A common stock
 
$
94,243
   
$
(182,147
)
 
$
(33,809
)
                         
Denominator:
                       
Weighted-average shares - diluted
   
201,703,176
     
106,654,918
     
20,862,555
 
Net income (loss) per share - diluted
 
$
0.47
   
$
(1.71
)
 
$
(1.62
)

The following table presents potentially dilutive securities excluded from the computation of diluted net loss per share for the years ended December 31, 2020 and 2019 because its effects would have been anti-dilutive. All potentially dilutive securities are included in the computation of diluted net income for the year ended December 31. 2021.

    Year Ended December 31,  
 
  2021     2020     2019  
Unvested RSUs(1)
   
-
     
1,538,060
      3,137,415  
Class B shares(2)
   
-
     
-
      144,342,572  
Shannon Equity Agreement shares(3)
   
-
     
428,275
      1,083,995  
Total
   
-
     
1,966,335
      148,563,982  

(1)
Represents the number of instruments outstanding at the end of the period.
(2)
Class B shares at the end of the period are considered potentially dilutive Class A shares.
(3)
Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.


The Company declared dividends totaling $79,834 during year ended December 31, 2021, representing $0.10 per Class A share. The Company paid $79,700 of dividends during the year ended December 31, 2021, inclusive of dividends that were accrued in prior periods.



After the Mergers, the Company paid a dividend of $9,056 to holders of GMLP’s 8.75% Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”). As these equity interests have been issued by the Company’s consolidated subsidiary, the value of the Series A Preferred Units is recognized as non-controlling interest in the consolidated financial statements.


23.
Share-based compensation

RSUs
 
The Company has granted RSUs to select officers, employees, non-employee members of the board of directors and select non-employees under the New Fortress Energy Inc. 2019 Omnibus Incentive Plan. The fair value of RSUs on the grant date is estimated 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.

The following table summarizes the RSU activity for the year ended December 31, 2021:

 
 
Restricted Stock
Units
   
Weighted-average
grant date fair
value per share
 
Non-vested RSUs as of December 31, 2020
   
1,538,060
   
$
13.49
 
Granted
   
-
     
-
 
Vested
   
(818,846
)
   
13.45
 
Forfeited
   
(42,876
)
   
13.71
 
Non-vested RSUs as of December 31, 2021
   
676,338
   
$
13.49
 

The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the years ended December 31, 2021, 2020 and 2019:

 
Year Ended December 31,
 
   
2021
   
2020
    2019  
Operations and maintenance
 
$
848
   
$
800
    $ 853  
Selling, general and administrative
   
5,728
     
7,943
      40,594  
Total share-based compensation expense
 
$
6,576
   
$
8,743
    $ 41,447  

For the years ended December 31, 2021, 2020 and 2019, cumulative compensation expense recognized for forfeited RSU awards of $212, $914 and $2,248, respectively, was reversed. The Company recognizes the income tax benefits resulting from vesting of RSUs in the period of vesting, to the extent the compensation expense has been recognized.

As of December 31, 2021, the Company had 676,338 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $1,031. The non-vested RSUs will vest over a period from ten months to three years following the grant date. The weighted-average remaining vesting period of non-vested RSUs totaled 0.18 years as of December 31, 2021.

Performance Share Units (“PSUs”)
 

During the first quarter of 2020 and 2021, the Company granted PSUs to certain employees and non-employees that contain a performance condition. Vesting is determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. During the fourth quarter of 2021, the Company determined that the 2020 Grant will vest at a multiple of two, resulting in vesting of 2,219,554 PSUs. Compensation cost for the full service period since the grant date of $30,467 was recognized in the fourth quarter of 2021. Vesting became probable for the 2020 Grant due to significant cargo sales successfully executed during the fourth quarter of 2021. As of December 31, 2021, the Company determined that it was not probable that the performance condition required for the 2021 Grant to vest would be achieved, and as such, no compensation expense has been recognized for this award.


                              
Unrecognized
 
Weighted Average
  Units Vested /
 
Compensation
 
Remaining Vesting
PSUs Granted
 
Units Granted
 
Range of Vesting
  Probable of Vesting
 
Cost⁽¹⁾
 
Period
Q1 2020 (“2020 Grant”)
   
1,109,777
 
0 to 2,219,554
  2,219,554  
$
-
 
-
Q1 2021 (“2021 Grant”)
   
400,507
 
0 to 801,014
  -  

31,932
 
1 year

⁽¹⁾ Unrecognized compensation cost is based upon the maximum amount of shares that could vest.

24.
Related party transactions

Management services

The Company is majority owned by Messrs. Edens (our chief executive officer and chairman of our Board of Directors) and Nardone (one of our Directors) who are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $6,509, $7,291 and $7,942 for the years ended December 31, 2021, 2020 and 2019, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2021 and 2020, $5,700 and $5,535 were due to Fortress, respectively.

In addition to administrative services, an affiliate of Fortress owns and leases an aircraft chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator rates, charter costs of $4,466, $2,483 and $5,367 for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, $944 and $472 was due to this affiliate, respectively.

Land lease
 
The Company has leased land and office space from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. In April 2019, FECI sold the office building to a non-affiliate, and as such, the lease of the office space is no longer held with a related party. The expense for the period that the building was owned by a related party during the year ended December 31, 2019 totaled $609, of which $386 was capitalized to Construction in progress and $223 was included in Selling, general and administrative in the consolidated statements of operations and comprehensive income (loss). The Company recognized expense related to the land lease still held by a related party of $526, $730 and $396 during the years ended December 31, 2021, 2020 and 2019, respectively, which was included within Operations and maintenance in the consolidated statements of operations and comprehensive income (loss). As of December 31, 2021 and 2020, $0 and $316 was due to FECI, respectively. As of December 31, 2021 and 2020, the Company has recorded a lease liability of $3,314 and $3,279, respectively, within Non-current lease liabilities on the consolidated balance sheets.

DevTech

In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest was reflected as non-controlling interest in the Company’s consolidated financial statements. DevTech purchased 10% of a note payable due to an affiliate of the Company. During the third quarter of 2021, the Company settled all outstanding amounts due under notes payable; the consulting agreement was also restructured to settle all previous amounts owed to DevTech and to include a royalty payment based on certain volumes sold in Jamaica. The Company paid $988 to settle these outstanding amounts. Subsequent to the restructuring of the consulting agreement, the Company recognized approximately $176 in expense for the year ended December 31, 2021. As of December 31, 2021, $88 was due to DevTech; no amounts were due from DevTech.

As of December 31, 2020, $715 was owed to DevTech on the note payable; prior to settlement, the outstanding note payable due to DevTech was included in Other long-term liabilities on the consolidated balance sheets. The interest expense on the note payable due to DevTech was $77 and $94 for the years ended December 31, 2020 and 2019, respectively. As of December 31, 2020, $343 was due from DevTech.

Fortress affiliated entities

The Company provides certain administrative services to related parties including Fortress affiliated entities. There are no costs incurred by the Company as the Company is fully reimbursed for all costs incurred. Beginning in the fourth quarter of 2020, the Company began to sublease a portion of office space to an affiliate of an entity managed by Fortress, and for the years ended December 31, 2021 and 2020, $799 and $204, respectively, of rent and office related expenses were incurred by this affiliate. As of December 31, 2021 and 2020, $1,241 and $1,540 were due from affiliates, respectively.

Additionally, an entity formerly affiliated with Fortress and currently owned by Messrs. Edens and Nardone provides certain administrative services to the Company, as well as providing office space under a month-to-month non-exclusive license agreement. The Company incurred rent and administrative expenses of approximately $2,444, $2,357 and $811 for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021 and 2020, $2,444 and $2,657 were due to Fortress affiliated entities, respectively.

Agency agreement with PT Pesona Sentra Utama (or PT Pesona)

PT Pesona, an Indonesian company, owns 51% of the issued share capital in the Company’s subsidiary, PTGI, the owner and operator of NR Satu, and provides agency and local representation services for the Company with respect to NR Satu. PT Pesona and certain of its subsidiaries also charged vessel management fees to the Company for the provision of technical and commercial management of the vessels; total expenses incurred to PT Pesona were $434 for the year ended December 31, 2021, respectively.

Hilli guarantees

As part of the GMLP Merger, the Company agreed to assume a guarantee (the “Partnership Guarantee”) of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. The Company also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under the LTA. Under the LOC Guarantee, the Company is severally liable for any outstanding amounts that are payable, up to approximately $19,000.

Subsequent to the GMLP Merger, under the Partnership Guarantee and the LOC Guarantee NFE’s subsidiary, GMLP, is required to comply with the following covenants and ratios:

•  free liquid assets of at least $30 million throughout the Hilli Leaseback period;
•  a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1; and
•  a consolidated tangible net worth of $123.95 million.

As of December 31, 2021, the amount the Company has guaranteed under the Partnership Guarantee and the LOC Guarantee is $356,250, and the fair value of debt guarantee after amortization, presented under Other current liabilities and Other non-current liabilities on the consolidated balance sheet, amounted to $4,918 and $2,320, respectively. As of December 31, 2021 the Company was in compliance with the covenants and ratios for both Hilli guarantees.

CELSE inventory purchases

During the fourth quarter of 2021, the Company purchased 3.1 TBtus of LNG from CELSE for $35,173. The inventory purchased from CELSE was subsequently sold prior to December 31, 2021. As of December 31, 2021, there were no outstanding amounts payable to CELSE for the purchase of LNG.

25.
Customer concentrations

For the year ended December 31, 2021, revenue from two significant customers constituted 25% of the total revenue. In addition, as a result of significant cargo sales revenue generated during 2021, one counterparty constituted 23% of total revenue for the year ended December 31, 2021. For the year ended December 31, 2020, revenue from three significant customers constituted 88% of the total revenue. For the year ended December 31, 2019, revenue from two significant customers constituted 74% of the total revenue. These customers’ revenues are included in the Company’s Terminals and Infrastructure segment.

During the years ended December 31, 2021, 2020 and 2019, revenue from external customers that were derived from customers located in the United States were $203,477, $135,702 and $21,386, respectively, and from customers outside of the United States were $1,119,333, $315,948, and $167,739. The Company attributes revenue from customers to the country in which the party to the applicable agreement has its principal place of business.

As of December 31, 2021 and 2020, long lived assets, which are all non-current assets excluding investment in equity securities, restricted cash, deferred tax assets, goodwill and intangible assets, located in the United States were $633,125 and $442,199, respectively, and long lived assets located outside of the United States were $4,722,589 and $639,370, respectively, primarily located in Brazil and the Caribbean.


26.
Segments



As of December 31, 2021, the Company operates in two reportable segments: Terminals and Infrastructure and Ships:



Terminals and Infrastructure includes the Company’s vertically integrated gas to power solutions, spanning 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. Leased vessels as well as acquired vessels that are utilized in the Company’s terminal or logistics operations are included in this segment.

Ships includes FSRUs and LNG carriers that are leased to customers under long-term or spot arrangements. FSRUs are stationed offshore for customer’s operations to regasify LNG; six of the FSRUs acquired in the Mergers are included in this segment, including the Nanook. LNG carriers are vessels that transport LNG and are compatible with many LNG loading and receiving terminals globally. Five of the LNG carriers acquired in the Mergers are included in this segment.  The Company’s investment in Hilli LLC is also included in the Ships segment.


The CODM uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to instruments recognized at fair value. Terminals and Infrastructure Segment Operating Margin includes our effective share of revenue, expenses and operating margin attributable to our 50% ownership of CELSEPAR. Ships Operating Margin includes our effective share of revenue, expenses and operating margin attributable to our ownership of 50% of the common units of Hilli LLC.



Management considers Segment Operating Margin to be the appropriate metric to evaluate and compare the ongoing operating performance of the Company’s segments on a consistent basis across reporting periods as it eliminates the effect of items which management does not believe are indicative of each segment’s operating performance.



The table below presents segment information for the years ended December 31, 2021, 2020 and 2019:


Year Ended December 31, 2021
 
(in thousands of $)
 
Terminals and
Infrastructure⁽¹⁾
   
Ships⁽²⁾
   
Total Segment
   
Consolidation
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
 
Balance sheet:
                                       
Total assets(4)
 
$
4,775,392
   
$
2,101,100
   
$
6,876,492
   
$
-
   
$
6,876,492
 
Other segmental financial information:
                                       
Capital expenditures(4)(5)
 
$
833,910
   
$
8,293
   
$
842,203
   
$
-
   
$
842,203
 


Year Ended December 31, 2020
 
(in thousands of $)
 
Terminals and
Infrastructure⁽¹⁾
   
Ships⁽²⁾
   
Total Segment
   
Consolidation
and Other⁽³⁾
   
Consolidated
 
Statement of operations:
                             
Total revenues
 
$
451,650
   
$
-
   
$
451,650
   
$
-
   
$
451,650
 
Cost of sales
   
278,767
     
-
     
278,767
     
-
     
278,767
 
Vessel operating expenses
   
-
     
-
     
-
     
-
     
-
 
Operations and maintenance
   
47,581
     
-
     
47,581
     
-
     
47,581
 
Segment Operating Margin
 
$
125,302
   
$
-
   
$
125,302
   
$
-
   
$
125,302
 
Balance sheet:
                                       
Total assets(4)
 
$
1,908,091
   
$
-
   
$
1,908,091
   
$
-
   
$
1,908,091
 
Other segmental financial information:
                                       
Capital expenditures(4)(5)
 
$
340,603
   
$
-
   
$
340,603
   
$
-
   
$
340,603
 


Year Ended December 31, 2019
 
   
Terminals and
               
Consolidation
       
(in thousands of $)
 
Infrastructure⁽¹⁾
   
Ships⁽²⁾
   
Total Segment
   
and Other⁽³⁾
   
Consolidated
 
Statement of operations:
                             
Total revenues
 
$
189,125
   
$
-
   
$
189,125
   
$
-
   
$
189,125
 
Cost of sales
   
183,359
     
-
     
183,359
     
-
     
183,359
 
Vessel operating expenses
   
-
     
-
     
-
     
-
     
-
 
Operations and maintenance
   
26,899
     
-
     
26,899
     
-
     
26,899
 
Segment Operating Margin
 
$
(21,133
)
 
$
-
   
$
(21,133
)
 
$
-
   
$
(21,133
)
Other segmental financial information:
                                       
Capital expenditures⁽⁵⁾
 
$
319,560
   
$
-
   
$
319,560
   
$
-
   
$
319,560
 



⁽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 ended December 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 ended December 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 ended December 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.

⁽⁴⁾ Total assets and capital expenditure by segment refers to assets held and capital expenditures related to the development of the Company’s terminals and vessels. The Terminals and Infrastructure segment includes the net book value of vessels utilized within the Terminals and Infrastructure segment.

⁽⁵⁾ Capital expenditures includes amounts capitalized to construction in progress and additions to property, plant and equipment during the period.



Consolidated Segment Operating Margin is defined as net income (loss), adjusted for selling, general and administrative expenses, transaction and integration costs, depreciation and amortization, interest expense, other (income) expense, income from equity method investments and tax expense.



The following table reconciles Net income (loss), the most comparable financial statement measure, to Consolidated Segment Operating Margin:


   
Year Ended December 31,
 
(in thousands of $)
   
2021
     
2020
     
2019
 
Net income (loss)
 
$
92,711
   
$
(263,965
)
 
$
(204,319
)
Add:
                       
Selling, general and administrative
   
199,881
     
120,142
     
152,922
 
Transaction and integration costs
   
44,671
     
4,028
     
-
 
Contract termination charges and loss on mitigation sales
   
-
     
124,114
     
5,280
 
Depreciation and amortization
   
98,377
     
32,376
     
7,940
 
Interest expense
   
154,324
     
65,723
     
19,412
 
Other (income) expense, net
   
(17,150
)
   
5,005
     
(2,807
)
Loss on extinguishment of debt, net
   
10,975
     
33,062
     
-
 
(Income) from equity method investments
   
(14,443)
     
-
     
-
 
Tax provision
   
12,461
   
4,817
     
439
 
Consolidated Segment Operating Margin
  $ 581,807     $ 125,302     $ (21,133 )

27.
Subsequent events

On February 28, 2022, the Company entered into an amendment to the Revolving Facility to increase the commitments thereunder by $115,000. Borrowings under the Revolving Facility will now bear interest at a per annum rate based on the Secured Overnight Financing Rate, as opposed to LIBOR. The Applicable Margin for borrowings under the Revolving Facility based on the current usage of the facility has not changed. No changes were made to the maturity date or covenants.

F-55


Schedule II

Description
 
Balance at
Beginning of Year
   
Additions(1)(2)
   
Deductions
   
Balance at
End of Year
 
 
                       
Year ended December 31, 2021
                       
 
                       
Allowance for expected credit losses
 
$
545
   
$
1,614
   
$
-
   
$
2,159
 
                                 
Year ended December 31, 2020
                               
 
                               
Allowance for expected credit losses
   
-
     
545
     
-
     
545
 
 
                               
Year ended December 31, 2019
                               
 
                               
Allowance for doubtful accounts
   
257
     
-
     
(257
)
   
-
 

Note

(1)
Amount expensed is included within Selling, general and administrative.
(2)
Additions in 2020 include the cumulative effect of accounting change upon adoption of ASC 326 of $229 which is included within Accumulated deficit.

F-56