What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2022-03-01 compared with 2021-03-16 · 1012 added, 357 removed, 79 unchanged (95% of the section changed)

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.

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.

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.

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.

1 unchanged sentence

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.

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

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.

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.

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.

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.

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.

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 “Items 1 and 2:

Business and Properties” under “Toward a Carbon-Free Future”.

As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation.

We 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.

We expect that control of our vertical supply chain, from procurement to delivery of LNG, will help to reduce our exposure to future LNG price variations and enable us to supply our existing and future customers with LNG at a price that reinforces our competitive standing in the LNG market.

Our strategy is simple:

we seek to procure LNG at attractive prices using long-term agreements and through our own production, and we seek to sell natural gas (delivered through LNG infrastructure) or gas-fired power to customers that sign long-term, take-or-pay contracts.

Our Current Operations

Our management team has successfully employed our strategy to secure long-term contracts with significant customers in Jamaica and Puerto Rico, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina production in Jamaica, and the Puerto Rico Electric Power Authority (“PREPA”), each of which is described in more detail below.

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 natural gas liquefaction and storage facility located in Miami-Dade County, Florida (the “Miami Facility”).

Our long-term goal is to develop the infrastructure necessary to supply our existing and future customers with LNG produced primarily at our own facilities, including our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”).

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

Montego Bay Facility

Our storage and regasification terminal in Montego Bay, Jamaica (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.

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

Our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility”) commenced commercial operations in June 2019 and is capable of processing approximately six million gallons of LNG (500,000 MMBtu) per day.

The Old Harbour Facility supplies natural gas to the new 190MW Old Harbour power plant (the “Old Harbour Power Plant”) operated by SJPC.

The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP Plant”).

The CHP Plant supplies electricity to JPS under a long-term power purchase agreement.

The CHP Plant also provides steam to Jamalco under a long-term take-or-pay steam supply agreement.

On March 3, 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively.

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

In July 2020, we finalized the development of the micro-fuel handling facility in the Port of San Juan, Puerto Rico (the “San Juan Facility”).

The San Juan Facility is near the San Juan Power Plant and serves as our supply hub for the San Juan Power Plant and other industrial end-user customers in Puerto Rico.

We have delivered natural gas used for the commissioning of PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020.

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

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

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.

Other Development Projects

We are in the process of developing an LNG regasification facility and power plant at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”).

Initially, the La Paz Facility is expected to supply approximately 270,000 gallons of LNG (22,300 MMBtu) per day under an intercompany GSA for approximately 100 MW of power supplied by gas-fired modular power units that we plan to develop, own and operated, which may be increased to 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power.

In addition, we were declared the winner of a bid with CFEnergia for the supply of natural gas to power plants located in Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day and are in the process of finalizing definitive agreements for this supply.

We are also in the process of developing an LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”).

In February 2020, we entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, and we are in the process of constructing an approximately 300 MW natural gas-fired power plant that will consume approximately 700,000 gallons of LNG (57,500 MMBtus) per day.

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

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.

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”).

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

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.

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

Hygo and GMLP Acquisitions

Hygo Acquisition

On January 13, 2021, NFE and Lobos Acquisition Ltd., a Bermuda exempted company and our wholly-owned subsidiary (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (the “Hygo Merger Agreement”) with Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd.

(“Stonepeak”), pursuant to which Hygo Merger Sub will merge with and into Hygo (the “Hygo Merger”), with Hygo surviving the Hygo Merger as a wholly owned subsidiary of NFE.

As of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share.

At the effective time of the Hygo Merger:

(i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash.

The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.

The Hygo Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals and other customary closing conditions.

Upon completion of the acquisition of Hygo, we expect to acquire one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Terminal”) a 50% interest in a 1.5 GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in development in Pará, Brazil (the “Barcarena Terminal”) and Santa Catarina, Brazil (the “Santa Catarina Terminal”).

In addition, we expect to acquire Hygo’s vessel fleet, which consists of the Golar Nanook , a newbuild FSRU moored and in service at the Sergipe Terminal, and two operating LNG carriers, the Golar Celsius and the Golar Penguin , which may be converted into FSRUs.

GMLP Acquisition

On January 13, 2021, we entered into an Agreement and Plan of Merger (the “GMLP Merger Agreement) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability company and the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and an indirect subsidiary of NFE (“GMLP Merger Sub”), and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales and an indirect subsidiary of NFE (“GP Buyer”), pursuant to which GMLP Merger Sub will merge with and into GMLP, with GMLP surviving the merger as an indirect subsidiary of NFE (the “GMLP Merger”).

At the effective time of the GMLP Merger (the “GMLP Effective Time”), each common unit representing a limited partner interest in GMLP that is issued and outstanding as of immediately prior to the GMLP Effective Time will automatically be converted into the right to receive $3.55 in cash.

At the GMLP Effective Time, each of the incentive distribution rights of GMLP will be canceled and cease to exist, and no consideration shall be delivered in respect thereof.

Each 8.75% Series A Cumulative Redeemable Preferred Unit of GMLP issued and outstanding immediately prior to the GMLP Effective Time will be unaffected by the GMLP Merger and will remain outstanding, and no consideration shall be delivered in respect thereof.

Each outstanding unit representing a general partner interest of GMLP that is issued and outstanding immediately prior to the GMLP Effective Time will remain issued and outstanding immediately following the GMLP Effective Time.

Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General Partner pursuant to a Transfer Agreement dated as of January 13, 2021 for a purchase price of approximately $5 million, which is equivalent to $3.55 per general partner unit of GMLP.

The GMLP Merger Agreement may be terminated by NFE or GMLP (which, in the case of GMLP, must be approved by GMLP’s Conflicts Committee) under certain circumstances, including, among others, by either NFE or GMLP if the closing of the GMLP Merger has not occurred on or before July 13, 2021, and further provides that, upon termination of the GMLP Merger Agreement under certain circumstances, GMLP may be required to pay NFE a termination fee equal to approximately $9.4 million.

The GMLP Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals, the approval of the GMLP Merger Agreement by the majority of the holders of GMLP common units and other customary closing conditions.

Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel, the Hilli, which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, each of which are expected to help support our existing facilities and international project pipeline.

The majority of the FSRUs in GMLP’s fleet are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters.

GMLP’s uncontracted vessels are available for short term employment in the spot market.

Suape Development

On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape in the city of Ipojuca, State of Pernambuco, Brazil.

On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.(“ Pecém”) and Energética Camaçari Muricy II S.A (“Muricy”).

These companies collectively hold certain 15-year power purchase agreements totaling 288 MW for the development of the thermoelectric power plants in the State of Bahia, Brazil.

We will seek to obtain the necessary approvals from the Agência Nacional de Energia Elétrica (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics in order to develop and plan to construct a 288MW gas-fired power plant and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil.

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.

We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis.

We have continued to invoice our customers for these fixed minimum volumes even in cases when our customer’s consumption has decreased.

We 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.

Based on the essential nature of the services we provide to support power generation facilities, our development projects have not currently been significantly impacted by responses to the COVID-19 pandemic.

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.

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 and daily operations during the year ended December 31, 2020 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.

W e 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

We received an order from the Federal Energy Regulatory Commission (“FERC”) on June 18, 2020, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the Natural Gas Act.

While we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously.

The matter was raised during a FERC open meeting held on January 19, 2021 but was not resolved , is on the agenda during the FERC open meeting to be held on March 18, 2021, and remains pending.

We do not know if or when FERC will respond to our reply, or the outcome of any such response.

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.

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

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

Operating revenue

Other revenue

(in thousands of $)

Terminals and

Infrastructure⁽¹⁾

Total Segment

Consolidation

Statement of operations:

Total revenues

Operating expenses

Cost of sales

Vessel operating expenses

Operations and maintenance

Segment Operating Margin

⁽¹⁾ Terminals and Infrastructure includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR.

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

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 $)

Statement of operations:

Total revenues

Cost of sales

Vessel operating expenses

Operations and maintenance

Segment Operating Margin

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)

Old Harbour Facility

Montego Bay Facility

San Juan Power Plant

Total volumes delivered in the current period

Year Ended December 31,

Old Harbour Power Plant

Montego Bay Facility

San Juan Power Plant

Total volumes delivered in the current period

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

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

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

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 $)

December 31, 2021

Statement of operations:

Total revenues

Cost of sales

Vessel operating expenses

Operations and maintenance

Segment Operating Margin

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

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 .

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 $)

Selling, general and administrative

Transaction and integration costs

Contract termination charges and loss on mitigation sales

1 unchanged sentence

Total operating expenses

Operating loss

Operating income (loss)

Interest expense

Other expense (income), net

Other (income) expense, net

Loss on extinguishment of debt, net

Loss before taxes

Operating revenue from the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilities for the year ended December 31, 2020 was $318,311 which increased by $172,811 from $145,500 for the year ended December 31, 2019.

The increase was primarily driven by volumes sold from the Old Harbour Terminal, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020:

For the year ended December 31, 2020, we recognized $189,196 of revenue from volumes sold at the Old Harbour Facility, as compared to $41,229 for the year ended December 31, 2019.

Revenue recognized for the year ended December 31, 2020 included $112,334 from sales to the Old Harbour Power Plant and $76,862 from natural gas utilized in the CHP Plant and Jamalco’s boilers.

For the year ended December 31, 2020, the volume delivered to the Old Harbour Power Plant was 96.0 million gallons (8.0 TBtu) and the volume utilized in the CHP Plant and Jamalco’s boilers was 96.2 million gallons (7.9 TBtu).

For the year ended December 31, 2019, the volume delivered to the Old Harbour Power Plant was 22.2 million gallons (1.9 TBtu).

Additional revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco added $23,062 in revenue for the year ended December 31, 2020.

Operating revenue was also impacted by operations at our Montego Bay Facility, including the following:

In connection with the adoption of ASC 842, we no longer identify a lease of the Montego Bay Facility in our gas sale agreement with our customer.

Accordingly, interest income associated with the direct financing lease of the Montego Bay Facility is no longer recognized within Other revenue, and all amounts recognized as revenue for activities at the Montego Bay Facility were included in Operating revenue for the year ended December 31, 2020, resulting in an increase of $15,771 to Operating revenue.

The increase in Operating revenue is partially offset by a decrease in sales at the Montego Bay Facility.

The decrease in sales at the Montego Bay Facility was primarily due to a decrease in sales volume delivered to the Bogue Power Plant.

Revenue from sales at the Montego Bay Facility decreased $ 14,399 to $ 77,464 for the year ended December 31, 2020 as compared to $ 91,863 for the year ended December 31, 2019 .

The delivered volume at the Montego Bay Facility decreased by 16.3 million gallons ( 1.2 TBtu) from 110.5 million gallons ( 9.1 TBtu) during the year ended December 31, 2019 to 94.2 million gallons ( 7.9 TBtu) during the year ended December 31, 2020 .

Other revenue includes revenue from development services, which is recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our power generation facilities, and such services are included within certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities.

Other revenue increased $89,714 for the year ended December 31, 2020 as compared to the year ended December 31, 2019 , and the increases were due to the following:

Increase of $113,777 for development services in Puerto Rico for the year ended December 31, 2020, including conversion of the customer’s infrastructure within the San Juan Power Plant and gas used by our customer for testing and commissioning their assets.

Development services revenue recognized in the year ended December 31, 2020 included $118,757 for the customer’s use of 129.5 million gallons (10.7 TBtu) of natural gas as part of commissioning their assets.

Lower revenue recognized for the infrastructure projects for customers of the CHP Plant.

For the year ended December 31, 2020, we recognized $601 for the completion of infrastructure projects for customers of the CHP Plant, as compared to $11,933 for the year ended December 31, 2019.

Cost of sales

Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities, power generation facilities or to our customers.

Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility.

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

Cost of sales for the year ended December 31, 2020 was $278,767 which increased $95,408 from $183,359 for the year ended December 31, 2019.

C ost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $92,433 for the year ended December 31, 2020 as compared to the year ended December 31, 2019.

The increase was primarily attributable to the increase in volumes delivered of approximately 200% compared to the year ended December 31, 2019, partially offset by the decrease in LNG cost.

The weighted-average cost of LNG purchased from third parties decreased from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020.

The weighted-average cost of our inventory balance as of December 31, 2020 and 2019 was $0.40 per gallon ($4.81 per MMBtu) and $0.64 per gallon ($7.70 per MMBtu), respectively.

Charter costs associated with our expanded fleet increased Cost of sales by $ 5,763 for the year ended December 31, 2020 .

The increase was attributable to a full year of charter costs of the Old Harbour Facility in 2020 as well as additional costs associated with our San Juan Facility after the assets were placed in service in the third quarter of 2020 .

The increase in Cost of sales was partially offset by a decrease in costs associated with the infrastructure projects for customers of the CHP Plant and conversion of our customer’s infrastructure within the San Juan Power Plant of $ 11,482 as compared to the year ended December 31, 2019 .

Operations and maintenance

Operations and maintenance includes costs of operating our Facilities, exclusive of costs to convert that are reflected in Cost of sales.

Operations and maintenance for the year ended December 31, 2020 was $47,581, which increased $20,682 from $26,899 for the year ended December 31, 2019.

The increase is primarily a result of higher logistics costs of $ 9,727 for the year ended December 31, 2020 , primarily associated with the operations of additional charter vessels deployed.

Operations and maintenance also increased by $ 5,425 for the year ended December 31, 2020 for costs of operating the CHP Plant for the period after commencement of commercial operations in March 2020 and by $ 5,698 for costs of operating the San Juan Facility after our assets were placed in service in the third quarter of 2020 .

Net income (loss) before income from equity method investments and income taxes

Income from equity method investments

Tax provision

Net income (loss)

Selling, general and administrative

Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors and costs associated with development activities for projects that are in initial stages and development is not yet probable.

Selling, general and administrative for the year ended December 31, 2020, was $124,170 which decreased $28,752 from $152,922 for the year ended December 31, 2019.

The decrease was primarily attributable to decreased share-based compensation expense of $32,651, as well as decreases to professional fees of $3,743, as compared to the year ended December 31, 2019.

These decreases were partially offset by $8,344 of higher payroll costs associated with increased headcount.

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

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

Contract termination charges and loss on mitigation sales for the years ended December 31, 2020 and 2019 was $124,114 and $5,280, respectively.

Through 2020, the pricing of LNG in the open market was significantly lower than the pricing in our LNG supply agreement with Centrica.

In June 2020, we executed an agreement to terminate our obligation to purchase LNG from Centrica 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, among other reasons, take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs.

We purchased LNG in the open market for the remainder of our needs in 2020, significantly reducing our LNG supply cost from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020.

We experienced lower than expected consumption by some of our customers in the second quarter of 2020, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica.

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.

Loss on mitigation sales for the year ended December 31, 2019 was $5,280 which was attributable to losses incurred associated with undelivered quantities of LNG under firm purchase commitments due to storage capacity constraints.

We did not have such

transactions during the year ended December 31, 2021.

Depreciation and amortization

Depreciation and amortization for the year ended December 31, 2020 was $32,376, which increased $24,436 from $7,940 for the year ended December 31, 2019.

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:

Increase in depreciation of $3,582 for our Old Harbour Facility that went into service in June 2019;

Increase in depreciation of $9,515 for the CHP Plant that went into service in March 2020;

Increase in depreciation of $4,484 for the San Juan Facility that went into service in July 2020;

Additional depreciation of $4,499 recognized on our Montego Bay Facility during the year.

These assets were presented as direct financing leases prior to the adoption of ASC 842, and no depreciation for such assets was previously recorded.

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;

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 for the year ended December 31, 2020 was $65,723, which increased $46,311 from $19,412 for the year ended December 31, 2019, primarily as a result of the additional principal balances outstanding during 2020 under the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds, as compared to the Term Loan Facility (all defined below).

When the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds were replaced by the Senior Secured Notes in September 2020, the outstanding principal balances totaled $980,000, as compared to the Term Loan Facility principal amount as of December 31, 2019 of $495,000, which had been extinguished in January 2020.

As of December 31, 2020, we have issued $1,250,000 of Senior Secured Notes.

Other expense (income), net

Other expense (income), net for the year ended December 31, 2020 was $5,005, which increased $7,812 from income of ($2,807) for the year ended December 31, 2019, primarily as a result of the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG, a decrease in interest income, and an increase in unrealized loss on our investment in equity securities.

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,

Loss on extinguishment of debt, net

Loss on extinguishment of debt was $33,062 for the year ended December 31, 2020 as a result of the extinguishment of the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds in September 2020, as well as the loss recognized upon the extinguishment of the Term Loan Facility in January 2020.

Loss on extinguishment of debt for the year ended December 31, 2019 was $0 as we did not have any such transactions during the year.

Tax expense for the year ended December 31, 2020 was $4,817, which increased $4,378 from a tax expense of $439 for the year ended December 31, 2019.

During 2020, the CHP Plant began operations and we placed our assets at the San Juan Facility in service.

Certain of our Jamaican operations had increased earnings for the year ended December 31, 2020 without any historical net operating losses to offset additional tax expense.

We have recognized tax expense in Puerto Rico at a preferential tax rate due to our tax decree resulting in an effective tax rate lower than the U.S.

federal income tax rate.

We continue to have valuation allowances in many of our foreign jurisdictions and tax expense for earnings generated in many foreign jurisdictions has been limited.

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.

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

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.

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

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, 2020 include our Montego Bay Facility, Miami Facility, sales from our Old Harbour Facility to SJPC, and certain industrial end-users.

The CHP Plant commenced commercial operations during March 2020 , and our results now include revenue and results operations from sales of gas, power and steam from the CHP Plant.

We also completed the development of our San Juan Facility in third quarter of 2020 , and in the second quarter of 2020 , we began to deliver natural gas to the San Juan Power Plant for PREPA to use in the commissioning of their assets.

Our current results do not include revenue and operating results from other projects under development including the La Paz Facility, the Puerto Sandino Facility, or the Ireland Facility.

Our historical financial results do not reflect changes to our current long-term LNG supply agreement as well as new LNG supply agreements that will lower the cost of our LNG supply through 2030.

We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the year ended December 31, 2020 .

In June 2020 , we entered into 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 for the remainder of 2020 , we purchased all volumes needed for our operations on the open market, significantly reducing our LNG supply costs from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020 .

During 2020, we also entered into four LNG supply agreements for the purchase of approximately 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement.

Our historical financial results do not include the anticipated acquisitions of Hygo and GMLP as well as transaction and integration costs expected to be incurred associated with these acquisitions.

Upon completion of the acquisition of Hygo, we expect to acquire the Sergipe Terminal, a 50% interest in the Sergipe Power Plant, as well as the Barcarena Terminal and the Santa Catarina Terminal that are currently in development.

In addition, we expect to acquire one FSRU in service at the Sergipe Terminal and two operating LNG carriers which may be converted into FSRUs.

Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel.

The results of operations of Hygo and GMLP will begin to be included in our financial statements upon the closing of the acquisitions, expected in the first half of 2021.

Our results of operations in 2021 will also include transaction costs associated with these acquisitions as well as costs incurred to integrate the operations of Hygo and GMLP into our business.

We no longer qualify as an emerging growth company or “EGC”.

As an EGC we were able to take advantage of an exemption from providing an auditor’s attestation on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes Oxley Act.

Following the issuance of Senior Secured Notes in September 2020, we ceased to qualify as an EGC and can no longer take advantage of this exemption.

We are also now required to accelerate the adoption of certain new or revised accounting pronouncements.

Starting in 2020, we will incur additional costs associated with providing an auditor’s attestation report, adoption of accounting standards on an accelerated timeline, as well as additional audit costs resulting from PCAOB requirements .

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.

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 and cash generated from operations.

We may also elect to generate additional liquidity through future debt or equity issuances to fund developments and transactions.

We have historically funded our developments through proceeds from our IPO and debt and equity financing as follows:

Our IPO was completed on February 4, 2019, and we raised net proceeds of $268,010, inclusive of additional net proceeds raised from the exercise of the underwriter’s option to purchase additional shares and after deducting underwriting discounts and commissions and transaction costs.

In March 2019, we drew the remaining availability on our Term Loan Facility and had $495,000 of outstanding principal as of December 31, 2019.

In September 2019, we issued approximately $117,000 in Senior Secured Bonds and Senior Unsecured Bonds, and in December 2019, we issued an additional $63,000 in Senior Secured Bonds, which was fully funded by January 2020.

In January 2020, we borrowed $800,000 under the Credit Agreement and repaid the Term Loan Facility in full.

In September 2020, we issued $1,000,000 of Senior Secured Notes and repaid in full amounts due on the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds.

No principal payments are due on the Senior Secured Notes until maturity in 2025.

In December 2020, we received proceeds of $263,500 from the issuance of $250,000 of additional notes on the same terms as the Senior Secured Notes (subsequent to this issuance, these additional notes are included in the definition of Senior Secured Notes herein).

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.

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.

We have assumed total expenditures for all completed and existing projects to be approximately $ 1,181 million , with approximately $ 789 million having already been spent through December 31, 2020 .

This estimate represents the expenditures necessary to complete the La Paz Facility and the Puerto Sandino Facility, expected expenditures to serve new industrial end-users and other planned capital expenditures.

We expect to be able to fund all such committed projects with a combination of cash on hand and cash flows from operations.

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 $ 20 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 $ 139 million , has been capitalized.

We have obtained debt financing commitments from Morgan Stanley Senior Funding, Inc.

and Goldman Sachs Bank USA for loans in an aggregate principal amount of $ 1.7 billion , consisting of a $ 1.5 billion senior secured bridge facility (the “Bridge Loan”) and a $ 200 million senior secured revolving facility to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes.

If NFE utilizes the Bridge Loan, the facility will bear a fixed interest rate of 6.25% , subject to a step-up of 50 basis points every three months.

The Bridge Loan has a one -year term, is pre-payable without penalty and will automatically be converted into a seven -year term loan if it is not repaid in full at maturity.

The senior secured revolving facility has a term of approximately five years and bears interest based on the three -month LIBOR rate plus certain margins.

The following table summarizes the changes to our cash flows for the years ended December 31, 2020 and 2019, respectively:

Year Ended December 31,

(in thousands)

Cash flows from:

Operating activities

Investing activities

Financing activities

Net increase (decrease ) in cash, cash equivalents, and restricted cash

Cash (used in) operating activities

Our cash flow used in operating activities was $125,566 for the year ended December 31, 2020, which decreased by $108,695 from $234,261 for the year ended December 31, 2019.

The reduction in cash flow used in operating activities for the year ended December 31, 2020 was due to more favorable changes in working capital accounts.

Fluctuations in inventory balances led to an increase in operating cash flows of $23,230 for the year ended December 31, 2020 compared to a $50,345 decrease in operating cash flows for the year ended December 31, 2019.

The impact of increasing accounts payable and accrued liabilities on cash flows from operations was $55,514 for the year ended December 31, 2020 compared to $3,036 for the year ended December 31, 2019.

Cash (used in) investing activities

Our cash flow used in investing activities was $157,631 for the year ended December 31, 2020, which decreased by $218,533 from $376,164 for the year ended December 31, 2019.

Cash outflows for investing activities during the year ended December 31, 2020 were primarily used to complete the CHP Plant and the San Juan Facility, as well as construction of the La Paz Facility.

Cash used in investing activities during the year ended December 31, 2019 significant capital expenditures for development of our Old Harbour Facility, CHP Plant, San Juan Facility and Pennsylvania Facility, as well as payments for significant outstanding amounts to our suppliers that were accrued as of December 31, 2018.

Cash provided by financing activities

Our cash flow provided by financing activities was $819,498 for the year ended December 31, 2020, which increased by $216,891 from $602,607 for the year ended December 31, 2019.

Cash provided by financing activities during the year ended December 31, 2020 was due to proceeds received from the borrowings under the Senior Secured Notes of $1,250,000, the Credit Agreement of $800,000 and Senior Secured Bonds of $52,144.

A portion of these proceeds from the Senior Secured Notes were used to fund the repayment of the Credit Agreement of $800,000, the Senior Secured Bonds and Senior Unsecured Bonds of $183,600 and the Term Loan Facility of $506,402.

The proceeds received were further offset by transaction costs and other fees incurred to obtain the borrowings.

In 2020, we also received proceeds from the issuance of Class A common stock of $291,922, offset by stock issuance costs of $1,107.

Cash dividends of $33,742 were paid, partially offsetting financing inflows.

Cash flow provided by financing activities during the year ended December 31, 2019 were primarily consisted of the issuance of Senior Secured Bonds and Senior Unsecured Bonds of $117,000 in September 2019, additional borrowings under the Term Loan Facility of $220,000 in March 2019 and proceeds received from our IPO of $274,948 in February 2019.

Long-Term Debt

Senior Secured Notes

On September 2, 2020 , the Company issued $ 1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144 A under the Securities Act (the “Senior Secured 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 Senior Secured Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The Senior Secured Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral.

The Senior Secured 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 Senior Secured Notes also provide for customary events of default and prepayment provisions.

We used a portion of the net cash proceeds received from the Senior Secured Notes to repay in full the outstanding principal and interest under the Credit Agreement, including related costs and expenses.

We also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds, including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds.

The redemption of the Senior Secured Bonds and Senior Unsecured Bonds was completed on September 21, 2020 .

In connection with the issuance of the Senior Secured 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 Senior Secured Notes on the consolidated balance sheets;

unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the Senior Secured Notes were $ 6,501 and such unamortized costs were also included as a reduction of the principal balance of the Senior Secured Notes and will be amortized over the remaining term of the Senior Secured Notes.

As a portion of the repayment of the Credit Agreement was a modification, we recorded $ 4,028 of third -party fees in Selling, general and administrative in the consolidated statements of operations and comprehensive loss.

On December 17, 2020 , the Company issued $ 250,000 of additional notes on the same terms as the Senior Secured Notes in a private offering pursuant to Rule 144 A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of Senior Secured Notes herein).

Proceeds received included a premium of $ 13,125 , which was offset by additional financing costs incurred of $ 4,188 .

As of December 31, 2020 , total remaining unamortized deferred financing costs were $ 10,439 .

The Credit Agreement

On January 10, 2020, the Company entered into a credit agreement to borrow $800,000 in term loans (the “Credit Agreement”).

The Credit Agreement was to mature in January 2023 with the full principal balance due upon maturity.

Interest was payable quarterly and was based on a LIBOR rate divided by one minus the applicable reserve requirement, subject to a floor of 1.50%, plus a margin of 6.25%.

The interest rate margin was to increase each year of the term by 1.50%.

Outstanding balances could be prepaid at our option at any time without premium.

We used a portion of the proceeds received to extinguish the Term Loan Facility.

We were required to comply with certain financial covenants as well as usual and customary affirmative and negative covenants, including limitations on liens and incurring additional indebtedness.

The facility also provided for customary events of default and cure provisions.

In connection with obtaining the Credit Agreement and the extinguishment of the Term Loan Facility, the Company incurred $37,051 in origination, structuring and other fees which were recognized as a reduction of the principal balance of the Credit Agreement on the consolidated balance sheets.

On September 2, 2020, we repaid the full amount outstanding using proceeds from the Senior Secured Notes.

Certain holders of the Credit Agreement participated in the issuance of Senior Secured Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification.

For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the consolidated statements of operations and comprehensive loss.

The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the Senior Secured Notes.

Term Loan Facility

On August 16, 2018, the Company entered into a credit agreement with a syndicate of two lenders to borrow up to an aggregate principal amount of $240,000.

On December 31, 2018, the Company amended this credit agreement (as amended, the “Term Loan Facility”) to, among other things, (i) increase the amount available for borrowing thereunder from $240,000 to $500,000, (ii) extend the initial maturity date to December 31, 2019, (iii) modify certain provisions relating to restrictive covenants and existing financial covenants, and (iv) remove the mandatory prepayment required with the net proceeds received in connection with an IPO.

As of December 31, 2018, the outstanding principal balance under the Term Loan Facility was $280,000.

On March 21, 2019, the Company drew an additional $220,000, bringing our total outstanding borrowings to $500,000 under the Term Loan Facility, and as of December 31, 2019 , the total principal amount outstanding under the Term Loan Facility was $ 495,000 .

All borrowings under the Term Loan Facility bore interest at a rate selected by us of either (i) LIBOR divided by one minus the applicable reserve requirement plus a spread of 4% or (ii) subject to a floor of 1%, a Base Rate equal to the higher of (a) the Prime Rate, (b) the Federal Funds Rate plus 1/2 of 1% or (c) the 1-month LIBOR rate plus 1.00% plus a spread of 3.0%.

The Term Loan Facility was repayable in quarterly installments of $1,250 with a balloon payment due at maturity.

The Term Loan Facility was secured by mortgages on certain properties owned by our subsidiaries, in addition to other collateral.

The Term Loan Facility was amended in the third quarter of 2019 to allow certain properties of a consolidated subsidiary to secure the Senior Secured Bonds.

We were also required to comply with certain financial covenants and other restrictive covenants customary for facilities of this type, including restrictions on indebtedness, liens, acquisitions and investments, restricted payments and dispositions.

We incurred costs in connection with obtaining the Term Loan Facility, the extinguishment of our prior debt facilities, and the amendment of the Term Loan Facility.

Some of the costs incurred were capitalized as a reduction to the Term Loan Facility on the consolidated balance sheets, and all deferred financing costs associated with the Term Loan Facility were amortized over the term of the Term Loan Facility, through December 31, 2019.

As such, there were no unamortized deferred financing costs as of December 31, 2019.

The Term Loan Facility had a maturity date of December 31, 2019 with an option to extend the maturity date for two additional six-month periods.

Upon the exercise of each extension option, we would pay a fee equal to 1.0% of the outstanding principal balance at the time of the exercise, and the spread on the LIBOR and Base Rate would increase by 0.5%.

On December 30, 2019, the Company entered into an amendment with the lenders to extend the maturity to January 21, 2020.

Prior to this new maturity date, on January 15, 2020, we repaid the full amount outstanding, using proceeds from the Credit Agreement to extinguish the Term Loan Facility.

South Power Bonds

On September 2, 2019, NFE South Power Holdings Limited (“South Power”), a consolidated subsidiary of the Company, entered into a facility for the issuance of secured and unsecured bonds (the “Senior Secured Bonds” and “Senior Unsecured Bonds”, respectively) and subsequently issued $73,317 and $43,683 in Senior Secured Bonds and Senior Unsecured Bonds, respectively.

The Senior Secured Bonds are secured by the CHP Plant and related receivables and assets, and the proceeds will be used to fund the completion of the CHP Plant and to reimburse shareholder advances.

In the fourth quarter of 2019, South Power issued an additional $63,000 in Senior Secured Bonds.

We received $10,856 of the proceeds in 2019 and received the remaining proceeds of $52,144 in January 2020.

The Senior Secured Bonds bore interest at an annual fixed rate of 8.25% and matured 15 years from the closing date of each issuance.

No principal payments were due for the first seven years.

Beginning in 2026, quarterly principal payments of approximately 1.6% of the original principal amount were due, with a 50% balloon payment due upon maturity.

Interest payments on outstanding principal balances were due quarterly.

The Senior Unsecured Bonds bore interest at an annual fixed rate of 11.00% and matured in September 2036.

No principal payments were due for the first nine years.

Beginning in 2028, principal payments were due quarterly on an escalating schedule.

Interest payments on outstanding principal balances were due quarterly.

South Power was required to comply with certain financial covenants as well as customary affirmative and negative covenants, including limitations on incurring additional indebtedness.

The facility also provided for customary events of default, prepayment and cure provisions.

The Company paid approximately $ 3,892 of fees in connection with the issuance of Senior Secured Bonds and Senior Unsecured Bonds.

These fees were capitalized on a pro-rata basis as a reduction of the Senior Secured Bonds and Senior Unsecured Bonds on the consolidated balance sheets.

On September 21, 2020 , the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the Senior Secured Notes and cash on hand.

In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds, the Company recognized a loss on extinguishment of debt of $ 7,195 in the consolidated statements of operations and comprehensive loss, including the write-off of $ 3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $ 3,601 .

Off Balance Sheet Arrangements

As of December 31, 2020 and 2019, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

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

2 unchanged sentences

(in thousands)

Less than 1 year

More than 5 years

Long-term debt obligations

2 unchanged sentences

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, 2020.

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, 2020.

In 2020, we entered into four LNG supply agreements for the purchase of 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030.

Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029.

The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract executed in December 2018.

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.

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

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 five vessels under time charter leases with non-cancellable terms ranging from nine months to seven 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 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 expect to begin to receive these ISO tanks and for the lease terms to commence beginning in the first 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 a space shared with affiliated companies in New York with lease terms up to 38 months and an office space in downtown Miami, with a lease term of 84 months.

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.

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.

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)

Cash flows from:

Operating activities

Investing activities

Financing activities

Net (decrease) increase in cash, cash equivalents, and restricted cash

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

Long-Term Debt and Preferred Stock

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.

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

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;

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.

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.

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

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

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”).

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

899.4($160.3)

Inter-American Development Bank

744.1($132.6)

3M LIBOR + 5.4%

IDC China Fund

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

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

(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

(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;

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.

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

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

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

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.

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.

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

Our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, and beginning in the first quarter of 2020, power and steam which are outputs from our natural gas-fueled infrastructure.

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 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 typically delivered in containers transported by truck to customer sites.

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 these agreements meets the exception for allocating variable consideration to each unit sold under the contract.

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 LNG or natural gas may contain a lease of equipment.

We allocate consideration received from customers 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 estimated fair value of the leased equipment, as a percentage of the estimated total revenue from LNG or natural gas and leased equipment at inception, will establish the allocation percentage to determine the fixed lease payments and the amount to be accounted for under the revenue recognition guidance.

The leases of certain facilities and equipment to customers are accounted for as finance or operating leases.

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 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 is included in Other revenue in the consolidated statements of operations and comprehensive loss.

The principal components of the lease payment are reflected as a reduction to the net investment in the finance lease.

For our operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the consolidated statements of operations and comprehensive loss.

In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes development services revenue recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities.

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 development 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.

Development services are typically included in arrangements that include other distinct performance obligations, and we allocate the transaction price to each performance obligation based on its standalone selling price (“SSP”) in relation to the aggregate value of the SSP of all performance obligations in the arrangement.

Some of our performance obligations have observable inputs that are used to determine the SSP of those distinct performance obligations.

Where SSP is not directly observable, we primarily determine the SSP using the cost-plus approach.

In the circumstances when available information to determine SSP is highly variable or uncertain, we use the residual approach.

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.

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

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.

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

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.

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.

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.

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.

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.

We have considered that the market price of LNG can vary widely, including recent decreases throughout 2019 and 2020.

Due to the decline in LNG prices, we executed three long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower than inventory purchased under our contract with our current supplier.

Further, we were able to take advantage of lower market pricing for LNG to supply our operations for the second half of 2020, resulting in an overall lower average cost of LNG.

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 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, we do not believe that changes in the price of LNG 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, 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 these customers, and there has not been any deterioration in the timing or volume of collections.

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 has 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.

We do not believe that oil prices will remain at their historic low levels as evidenced by recent recovery, and we believe that LNG and natural gas will remain a competitive fuel source for customers.

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.

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.

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.

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.

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.

As of December 31, 2020, management determined that it was not probable that the performance condition for our outstanding PSUs would be met.

For these awards, compensation cost and the number of PSUs ultimately earned remains variable and compensation cost for these awards is recorded once achievement of the performance conditions becomes probable through the requisite service period.

A cumulative adjustment to share-based compensation expense is recorded in the period that achievement of performance conditions becomes probable.

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

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.

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

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, see “Note 3 - Adoption of new and revised standards” to our notes to consolidated financial statements included elsewhere in this Annual Report.

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis