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Item 2. Management’s Discussion and Analysis

2022-05-06 compared with 2021-11-03 · 380 added, 979 removed, 130 unchanged (91% of the section changed)

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

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our

business and related financing, includes forward-looking statements.

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements.

Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties.

Actual events or results may differ materially from the

results anticipated in these forward-looking statements as a result of a variety of factors.

You should read “Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and under similar

headings in the Annual Report on Form 10-K for the year ended December 31, 2020 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the

forward-looking statements contained in the following discussion and analysis.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this

Quarterly Report.

Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors.

You should read “Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and under similar headings in the Annual Report on Form 10-K for the year ended December 31, 2021 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report.

Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“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.

This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance.

Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion.

Unless otherwise indicated,

dollar amounts are presented in thousands.

Unless the context otherwise requires, references to ‘‘Company,’’ ‘‘NFE,’’ ‘‘we,’’ ‘‘our,’’ ‘‘us’’ or similar terms refer to (i) prior to our conversion from a limited liability company to a

corporation, New Fortress Energy LLC and its subsidiaries and (ii) following the conversion from a limited liability company to a corporation, New Fortress Energy Inc.

Unless otherwise indicated, dollar amounts are presented in thousands.

Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to our conversion from a limited liability company to a corporation, New Fortress Energy LLC and its subsidiaries and (ii) following the conversion from a limited liability company to a corporation, New Fortress Energy Inc.

and its subsidiaries.

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.

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 energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable, and clean energy.

We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets.

Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide.

Our long-term mission is to become one of the world’s leading carbon emission-free independent power providing companies.

We discuss this important goal in

more detail in the Annual Report, “Items 1 and 2:

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

On April 15, 2021, we completed the acquisitions of Hygo Energy Transition Ltd.

(“Hygo”) and Golar LNG Partners LP (“GMLP”);

referred to as the “Hygo Merger” and “GMLP Merger,” respectively and,

collectively, the “Mergers”.

NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger.

NFE paid $3.55 per each common unit of GMLP outstanding and for each of the

outstanding membership 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.

As a result of the Mergers, we acquired one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power

Plant”), as well as two other FSRU terminals in development in Pará, Brazil (the “Barcarena Facility”) and Santa Catarina, Brazil (the “Santa Catarina Facility”).

We acquired the Nanook , a newbuild FSRU moored and in service at the Sergipe Facility.

In addition to the Nanook, the

we also acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (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 are operating in Brazil, Kuwait, Indonesia, Jamaica and

Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market.

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 discuss this important goal in more detail in our 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.” As a result of the Hygo Merger, the Company acquired a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”) and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), as well as a terminal and power plant under development in the State of Pará, Brazil (the “Barcarena Facility” and "Barcarena Power Plant," respectively), a terminal under development on the southern coast of Brazil (the “Santa Catarina Facility”) and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility.

As a result of the Mergers, 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.

Acquired FSRUs are operating in Brazil, Indonesia and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market.

Subsequent to the completion of the Mergers, our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships.

Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation.

We currently source LNG from long-term supply agreements with third party suppliers and from our own liquefaction facility in Miami, Florida.

Leased vessels as well as the cost to operate our

vessels that are utilized in our terminal or logistics operations are included in this segment.

The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico and Brazil, including our interest in the Sergipe

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 allows us to 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.

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

Our assets built to service these significant customers have been designed with capacity to service other customers.

We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our Miami Facility.

Our long-term goal is to develop the infrastructure necessary to supply our

existing and future customers with LNG produced primarily at our own facilities, including Fast LNG and our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”).

We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our liquefaction facility in Dade County, Florida ("Miami Facility").

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

Montego Bay Facility

The Montego Bay Facility serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue Power Plant in Montego Bay, Jamaica.

Our Montego Bay Facility

commenced commercial operations in October 2016 and is capable of processing up to 740,000 gallons of LNG (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage.

The Montego Bay Facility also consists of an ISO

loading facility that can transport LNG to numerous on-island industrial users.

Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 61,000 MMBtu of LNG per day and features approximately 7,000 cubic meters of onsite storage.

The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.

Old Harbour Facility

The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing approximately six million gallons of LNG (500,000 MMBtus) per day.

The Old Harbour Facility

commenced commercial operations in June 2019 and supplies natural gas to the 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 Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day.

The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“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 (“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 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 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.

In the third quarter of 2021, commission for

Units 5 & 6 of the San Juan Power Plant to operate on natural gas was substantially completed under the terms of our agreement with PREPA.

See “—Other Matters” for additional information regarding our San Juan Facility.

Our San Juan Facility became fully operational in the third quarter of 2020.

It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico.

The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users.

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

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

Sergipe Power Plant and Sergipe Facility

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(“CELSEPAR”), which owns Centrais Elétricas de Sergipe S.A.

(“CELSE”), the owner and

operator of the Sergipe Power Plant.

("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 the largest natural gas-fired

thermal power station in South America and was built to provide electricity on demand, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the region.

CELSE has executed multiple PPAs pursuant

to which the Sergipe Power Plant is delivering power to 26 committed offtakers 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 acquired a 75% interest in Centrais Elétricas Barra dos Coqueiros S.A.

(“CEBARRA”), which owns rights to expand the Sergipe Power Plant.

These rights include 179 acres of land and

regulatory permits for an incremental 1.7GW of power generation.

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 Energia Ltda.

(“Ebrasil”), an affiliate of Eletricidade do Brasil S.A.

, of which we own 75%.

These rights include 190 acres of land and regulatory permits for two new power generation projects of 2.0GW in the aggregate.

CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions.

The Sergipe Facility is capable of processing up

to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG.

The Sergipe Facility is expected to utilize approximately 230,000 MMBtu/d (30% of the facility’s maximum regasification capacity) to provide natural gas to the Sergipe Power

Plant, at full dispatch.

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 per day (30% of the Sergipe Facility’s maximum regasification capacity) of natural gas 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.

This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG 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

Our Ships segment includes six FSRUs and five LNGCs, which are leased to customers under long-term or spot arrangements, including a 25-year charter of Nanook with CELSE.

As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment.

We began to use one acquired LNGC in our terminal operations in the

third quarter of 2021, and the results of operations of this vessel are no longer included in the Ships segment.

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.

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.

the LTA, Hilli Corp receives a monthly tolling fee, consisting of a fixed element of hire and incremental tolling fees based on the price of Brent crude oil.

Under the LTA, Hilli Corp receives a monthly tolling fee, consisting of a fixed element of hire and incremental tolling fees based on the price of Brent crude oil.

Our Development Projects

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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.

Once fully operational, the La Paz Facility is expected to supply approximately an additional 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 which we have developed, own and will operate once fully operational, which may be increased to approximately 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power.

The La Paz Facility is expected to supply approximately 22,300 MMBtu of LNG 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 29,000 MMBtu of LNG per day for up to 135MW of power.

Puerto Sandino Facility

Construction of our LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”) is expected to be completed

in the fourth quarter of 2021 with commissioning of the power plant expected to begin in the first quarter of 2022.

We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and our 300 MW natural gas-fired power

plant will consume approximately 700,000 gallons of LNG (57,500 MMBtus) per day.

Suape Facility

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

On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.

(“Pecém”) and Energetica Camacari Muricy II S.A.

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 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 Port of Suape and 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 (the “Suape Facility”).

We are developing an offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”).

We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 MMBtu of LNG 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/d and storing up to 170,000 cubic meters of LNG.

The Barcarena Facility is expected to utilize approximately 92,000 MMBtu/d (12% of the facility’s maximum regasification capacity) to service the Barcarena Power Plant upon

commencement of operations.

As part of the Mergers, we acquired multiple 25-year PPAs to support the construction of a 605 MW combined cycle thermal power plant to be located in Pará, Brazil and to be supplied by the

Barcarena Facility (the “Barcarena Power Plant”).

The Barcarena Power Plant will utilize LNG sourced and processed at the Barcarena Facility for the generation of electricity which will be distributed to the national electricity grid.

project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019.

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 790,000 MMBtu/d and LNG storage capacity of up

to 170,000 cubic meters.

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 gallons per day.

(“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”).

We intend for the Suape Facility to supply LNG to a 288MW thermoelectric power plant to also be located in the State of Pernambuco, Brazil (the “Suape Power Plant”).

With the purchase of CH4 Energia Ltda.

on January 12, 2021, 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.

We also 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.

Sri Lanka Facility

In September 2021, we signed an agreement to acquire a 40% ownership stake in West Coast Power Limited (“WCP”), the owner of the 310 MW Yugadanvi Power Plant in Colombo, Sri Lanka.

develop an offshore LNG receiving, storage and regasification terminal to supply the Kerawalapitya Power Complex, where 310 MW of power is operational today and an additional 700 MW scheduled to be built, of which 350 MW is scheduled to be

operational by 2023.

We expect to initially provide the equivalent of an estimated 1.2 million gallons of LNG per day (35,000 MMBtu/d), with the expectation of significant growth as new power plants become operational.

Our agreement with WCP is

subject to certain conditions precedent, and we expect that these conditions will be finalized in the first half of 2022.

We are currently developing a modular floating liquefaction facility to provide a low-cost supply of liquefied natural gas for our growing customer base.

The “Fast LNG” design pairs advancements

in modular, midsize liquefaction technology with jack up rigs or similar floating infrastructure to enable a much lower cost and faster deployment schedule than today’s floating liquefaction vessels.

A permanently moored FSU will serve as an LNG

storage facility alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

We plan to develop an offshore LNG receiving, storage and regasification terminal to supply the Kerawalapitya Power Complex, in Colombo, Sri Lanka, where 310 MW of power is operational today and an additional 700 MW is scheduled to be built.

We expect to initially provide the equivalent of an estimated 35,000 MMBtu of LNG per day, with the expectation of significant growth as new power plants become operational.

Ireland Facility

We intend to develop and operate an LNG facility (the “Ireland Facility”) and power plant on the Shannon Estuary, near Tarbert, Ireland.

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 series of modular floating liquefaction facilities to provide a source of 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 marine floating infrastructure to enable a much lower cost and faster deployment schedule than today’s floating liquefaction vessels.

Semi-permanently moored FSU(s) will serve as LNG storage 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

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 used flexibility in our operations and supply portfolio to sell a portion

of these cargos in the market, and these sales have positively impacted our results for the third quarter of 2021.

We expect to deliver these cargos in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations

in the fourth quarter of 2021.

Since August 2021, LNG prices have increased materially, and global events, such as Russia’s invasion of Ukraine, have generated further energy pricing volatility.

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 first quarter of 2022.

Cargo sales of 9.7 TBtus were completed in the first quarter of 2022, increasing our revenues and results of operations for the three months ended March 31, 2022.

COVID-19 Pandemic

We are closely monitoring the impact of the novel coronavirus (“COVID-19”) pandemic on all aspects of

our operations and development projects, including our marine operations acquired in the Mergers.

Customers in our Terminals and Infrastructure segment primarily operate under long-term

contracts, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis.

We continue to closely monitor 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.

changed our payment terms with these customers, and there has not been deterioration in the timing or volume of collections.

We have not changed our payment terms with these customers, and there has not been deterioration in the timing or volume of collections.

Many of the vessels acquired in the Mergers operate under long-term contracts with fixed payments.

We are required to have adequate crewing aboard our vessels to fulfill the obligations under our

contracts, and we have implemented safety measures to ensure that we have healthy qualified officers and crew.

We monitor local or international transport or quarantine restrictions limiting the ability to transfer crew members off vessels or

bring a new crew on board, and restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives, and we have not experienced significant disruptions in our operations due to these

measures or restrictions.

Based on the essential nature of the services we provide to support power generation facilities, our operations and development projects have not currently been significantly impacted by

responses to the COVID-19 pandemic.

We are required to have adequate crewing aboard our vessels to fulfill the obligations under our contracts, and we have implemented safety measures to ensure that we have healthy qualified officers and crew.

We monitor local or international transport or quarantine restrictions limiting the ability to transfer crew members off vessels or bring a new crew on board, and restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives, and we have not experienced significant disruptions in our operations due to these measures or restrictions.

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

We remain committed to prioritizing the health and well-being of our employees, customers, suppliers and other partners.

We have implemented policies to screen employees, contractors, and vendors for COVID-19

symptoms upon entering our development projects, operations and office facilities.

For the three months and nine months ended September 30, 2021, we have incurred approximately $0.2 million and $0.6 million, respectively, for safety measures

introduced into our operations and other responses to the COVID-19 pandemic.

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 implemented policies to screen employees, contractors, and vendors for COVID-19 symptoms upon entering our development projects, operations and office facilities.

From the beginning of 2020 to March 31, 2022, we have incurred approximately $2.2 million to date for safety measures introduced into our operations and other responses to the COVID-19 pandemic.

We are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread.

We have not experienced significant disruptions in development projects, charter or terminal operations from the COVID-19 pandemic;

however, there

are important uncertainties including the scope, severity and duration of the pandemic, the actions taken to contain the pandemic or mitigate its impact, and the direct and indirect economic effects of the pandemic and containment measures.

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.

however, there are important uncertainties including the scope, severity and duration of the pandemic, the actions taken to contain the pandemic or mitigate its impact, and the direct and indirect economic effects of the pandemic and containment measures.

We do not currently expect these factors to have a significant impact on our results of operations, liquidity or financial position, or our development budgets or timelines.

Other Matters

On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA.

Because we do not believe

that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously.

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 directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was 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.

Results of Operations – Three and Nine Months Ended September 30, 2021 compared to Three and Nine Months Ended September 30, 2020

Segment performance is evaluated based on segment operating margin and the tables below presents our segment information for the three and nine months ended September 30, 2021 and 2020:

Three Months Ended September 30, 2021

(in thousands of $)

Terminals and Infrastructure⁽¹⁾

Total Segment

Consolidation and Other⁽³⁾

Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021.

We have filed petitions for review of FERC’s March 19 and July 15 orders with the United States Court of the Appeals for the District of Columbia Circuit.

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 – Three Months Ended March 31, 2022 compared to Three Months Ended December 31, 2021 and Three Months Ended March 31, 2021

Segment performance is evaluated based on operating margin and the tables below present our segment information for the three months ended March 31, 2022, December 31, 2021 and March 31, 2021:

Three Months Ended March 31, 2022

(in thousands of $) Terminals and

Infrastructure (1)

Total Segment Consolidation

and Other (3)

Total revenues 480,349 114,942 595,291 (90,173) 505,118

3 unchanged sentences

Segment Operating Margin 211,083 89,000 300,083 (49,395) 250,688

Nine Months Ended September 30, 2021

(in thousands of $)

Terminals and Infrastructure⁽¹⁾

Total Segment

Consolidation and Other⁽³⁾

Three Months Ended December 31, 2021

(in thousands of $) Terminals and

Infrastructure (1)

Total Segment Consolidation

and Other (3)

Total revenues $ 689,770 $ 117,796 $ 807,566 $ (158,935) $ 648,631

3 unchanged sentences

Segment Operating Margin $ 278,354 $ 94,796 $ 373,150 $ (46,328) $ 326,822

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

The losses and earnings attributable to the investment

of $27,792 and $655 for the three and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of operations.

Terminals and Infrastructure does not

include the unrealized mark-to-market loss on derivative instruments of $2,316 for the three and nine months ended September 30, 2021 reported in Cost of sales.

⁽²⁾ Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units.

attributable to the investment of $11,809 and $22,303 for the three months and nine months ended September 30, 2021, respectively are reported in income (loss) from equity method investments on the condensed consolidated statements of

operations and comprehensive loss.

⁽³⁾ Consolidation and Other adjust 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 derivative instruments.

Terminals and Infrastructure

(in thousands of $)

ended September

Three Months Ended March 31, 2021

(in thousands of $) Terminals and

Infrastructure Ships Total Segment Consolidation

and Other Consolidated

Total revenues $ 145,684 $ — $ 145,684 $ — $ 145,684

3 unchanged sentences

Segment Operating Margin $ 32,761 $ — $ 32,761 $ — $ 32,761

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

The earnings and losses attributable to the investment of $36,680 and $18,580 for the three months ended March 31, 2022 and December 31, 2021, respectively, are reported in income (loss) from equity method investments in the consolidated statements of operations and comprehensive income (loss).

Terminals and Infrastructure does not include the unrealized mark-to-market gain and loss on derivative instruments of $2,492 and $472 for the three months ended March 31, 2022 and December 31, 2021, respectively, reported in Cost of sales.

(2) Ships includes our effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units.

The earnings attributable to the investment of $13,555 and $10,065 for the three months ended March 31, 2022 and December 31, 2021, respectively, are reported in income (loss) from equity method investments in the consolidated statements of operations and comprehensive income (loss).

(3) Consolidation and Other adjust for the inclusion of our 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 derivative instruments.

Terminals and Infrastructure Segment

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands of $)

Three Months Ended,

(in thousands of $) March 31, 2022 December 31, 2021 Change March 31, 2021 Change

Total revenues $ 480,349 $ 689,770 $ (209,421) $ 145,684 $ 334,665

4 unchanged sentences

Total revenue

Total revenue for the Terminals and Infrastructure Segment increased $212,282 and $370,418 for the three and nine months ended September 30, 2021 as compared to the three months and nine months

ended September 30, 2020, respectively.

The increase was primarily driven by increases in revenue from 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 2021, positively impacting our

The average Henry Hub index pricing used to invoice our customers increased by 103% and 69% for the three and nine months ended September 2021 as compared to the three and nine months ended September 30, 2020, respectively.

Additionally,

we recognized additional revenue from more volumes sold to the San Juan Power Plant in Puerto Rico.

Revenue from cargo sales outside of our terminal operations was $32,605 for the three and nine months ended September 30, 2021;

there were no comparable transactions in the three and nine months

ended September 30, 2020.

The Old Harbour Facility sold additional volumes in the three and nine months ended September 30, 2021 as compared to the three and nine months ended September 30, 2020, including volumes

utilized in the CHP Plant which commenced commercial operations during March 2020.

Increases in revenue were further impacted by substantial increases to natural gas pricing.

For the three months ended September 30, 2021, we recognized $62,488 of revenue from volumes sold at the Old Harbour Facility, as compared to $50,064 for the three months ended September 30, 2020, driven

primarily by an increase in the Henry Hub index used to invoice our customers when compared to the third quarter of 2020.

Volumes consumed at the Old Harbour Power Plant increased by 6.2 million gallons (0.6 TBtu), partially offset by a

decrease of 1.5 million gallons (0.2 TBtu) in consumption by Jamalco’s boilers.

Total revenue for the Terminals and Infrastructure Segment decreased $209,421 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

The decrease was primarily driven by lower revenue from LNG cargo sales to third parties.

Revenue from cargo sales was $285,171 for the three months ended March 31, 2022 and $422,880 for the three months ended December 31, 2021.

Our revenue was also negatively impacted by decreases to the Henry Hub index in the first quarter.

Our contracts with customers in this segment typically include a portion of pricing based on the Henry Hub index, and the average Henry Hub index pricing used to invoice our customers decreased by 15% for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

Total revenue for the Terminals and Infrastructure Segment increased $334,665 for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021.

We recognized revenue for LNG cargos sold to third parties and our share of revenue from our investment in CELSEPAR during the first quarter of 2022, totaling $348,560.

We did not have any cargo sales transactions in the first quarter of 2021, and the acquisition of our investment in CELSEPAR in the Mergers occurred subsequent to March 31, 2021.

Accordingly, the increased revenue was primarily driven by these transactions.

The following table summarizes the volumes delivered, exclusive of LNG cargo volumes sold to third parties, in the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and the three months ended March 31, 2021:

Three Months Ended

(in TBtu) March 31, 2022 December 31, 2021 Change March 31, 2021 Change

Old Harbour Facility 3.0 3.2 (0.2) 4.4 (1.4)

Montego Bay Facility 0.5 1.0 (0.5) 2.0 (1.5)

San Juan Facility 1.1 1.1 — 4.0 (2.9)

Other 1.7 1.2 0.5 0.3 1.4

Total volumes delivered in the current period 6.3 6.5 (0.2) 10.7 (4.4)

A summary of the impact to revenue from our operations at our Old Harbour Facility is as follows:

• Sales at the Old Harbour Facility decreased by $4,888 from $62,491 for the three months ended December 31, 2021 to $57,603 for the three months ended March 31, 2022.

The decrease in revenue from the Old Harbour Facility was due to revenue deferred for volumes delivered below the take-or-pay minimums in our contracts and a decrease in the Henry Hub index used to invoice our customers as compared to the three months ended December 31, 2021.

• Sales at the Old Harbour Facility increased by $6,065 from $51,538 for the three months ended March 31, 2021 to $57,603 for the three months ended March 31, 2022.

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 three months ended March 31, 2021, which was partially offset by a decrease in volumes delivered at the Old Harbour Power Plant.

• The Jamalco refinery experienced a fire in August 2021, and no gas volumes have been consumed by their boilers since this event.

Volumes delivered to the Old

Harbour Power Plant increased to 33.1 million gallons (2.8 TBtu) in the three months ended September 30, 2021 from 26.9 million gallons (2.2 TBtu) in the three months ended September 30, 2020.

Volumes delivered to the CHP Plant and

Jamalco’s boilers decreased to 27.1 million gallons (2.2 TBtu) in the three months ended September 30, 2021 from 28.6 million gallons (2.4 TBtu) in the three months ended September 30, 2020.

For the nine months ended September 30, 2021, we recognized $170,402 of revenue from volumes sold at the Old Harbour Facility, as compared to $129,313 for the nine months ended September 30, 2020, primarily

driven by an increase in the Henry Hub index used to invoice our customers and additional volumes consumed at the Old Harbour Power Plant, CHP Plant and Jamalco’s boilers, which began consuming gas in August 2020.

Volumes delivered to the

Old Harbour Power Plant increased by 13.5 million gallons (1.2 TBtu) to 91.9 million gallons (7.7 TBtu) in the nine months ended September 30, 2021 from 78.4 million gallons (6.5 TBtu) in the nine months ended September 30, 2020.

delivered to the CHP Plant and Jamalco’s boilers increased by 18.9 million gallons (1.5 TBtu) to 81.3 million gallons (6.7 TBtu) in the nine months ended September 30, 2021 from 62.4 million gallons (5.2 TBtu) in the nine months ended

September 30, 2020.

Revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco was $7,237 and $21,567 for the three and nine months ended September 30, 2021,

respectively, as compared to $7,280 and $15,957 in revenue for the three and nine months ended September 30, 2020, respectively.

After the fire at the Jamalco refinery, we did not deliver any steam to Jamalco.

However, steam revenue was

consistent in the third quarter of 2021 with previous periods as our contract with Jamalco has take-or-pay provisions that allow us to invoice for minimum volumes.

Revenue from the delivery of power and steam from the CHP Plant decreased by $5,713 and $5,591 from the three months ended December 31, 2021 and March 31, 2021, respectively, to $1,651 for the three months ended March 31, 2022.

Revenue was also impacted by operations at our Montego Bay Facility.

Sales at the Montego Bay Facility increased by $4,298 from $23,515 for the three months ended September 30, 2020 to $27,813 for the three months ended September 30, 2021.

The increase in sales at the

Montego Bay Facility was due to an increase in the Henry Hub index used to invoice our customers compared to the third quarter of 2020.

Volumes delivered at the Montego Bay Facility remained relatively consistent for the three months

ended September 30, 2021 as compared to the three months ended September 30, 2020, decreasing by 0.1 million gallons (0.0 TBtu) from 23.9 million gallons (2.0 TBtu) during the three months ended September 30, 2020 to 23.8 million gallons

(2.0 TBtu) during the three months ended September 30, 2021.

Sales at the Montego Bay Facility increased by $10,103 from $69,072 for the nine months ended September 30, 2020 to $79,175 for the nine months ended September 30, 2021.

The increase in sales at the Montego

Bay Facility was primarily due to an increase in the Henry Hub index used to invoice our customers compared to the first nine months of 2020.

Volumes delivered at the Montego Bay Facility increased by 1.9 million gallons (0.2 TBtu) from

70.5 million gallons (5.9 TBtu) during the nine months ended September 30, 2020 to 72.4 million gallons (6.1 TBtu) during the nine months ended September 30, 2021.

We also recognize revenue from development services for 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.

Such services are provided under certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities.

Natural gas delivered to the San Juan Power Plant was recognized as revenue from development services, until commissioning of Units 5 & 6 of the San Juan Power Plant to operate on natural gas was substantially completed in the third quarter

After this point, all natural gas delivered to the San Juan Power Plant was recognized as operating revenue.

Sales at the San Juan Power Plant increased by $24,087 from $51,974 for the three months ended September 30, 2020 to $76,061 for the three months ended September 30, 2021.

The increase was driven by

additional volumes consumed at the San Juan Power Plant.

Volumes delivered to the San Juan Power Plant increased by 13.0 million gallons (1.0 TBtu) to 71.6 million gallons (5.8 TBtu) in the three months ended September 30, 2021 from 58.6

million gallons (4.8 TBtu) in the three months ended September 30, 2020.

Sales at the San Juan Power Plant increased by $108,263 from $68,458 for the nine months ended September 30, 2020 to $176,721 for the nine months ended September 30, 2021.

The increase was driven by

additional volumes consumed at the San Juan Power Plant, as our San Juan Facility was not completed until July 2020.

Volumes delivered to the San Juan Power Plant increased by 88.0 million gallons (7.1 TBtu) to 165.9 million gallons

(13.5 TBtu) in the nine months ended September 30, 2021 from 77.9 million gallons (6.4 TBtu) in the nine months ended September 30, 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 $134,523 and $166,292 for the three and nine

months ended September 30, 2021, respectively, 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 quarter of

2021 by emergency dispatch due to poor hydrological conditions in Brazil during the third quarter.

Our proportionate share of revenue from the Sergipe Facility is included in this discussion as such revenue is included in our segment measure;

our consolidated statement of operations and comprehensive loss, we report the results from our investment in CELSEPAR as Income (loss) from equity method investments.

• During the first quarter of 2022, no volumes were consumed by the Bogue Power Plant, leading to the significant decrease in volumes delivered at the Montego Bay Facility, due to the port authority at the Port of Montego Bay where our facility resides requiring a reconfiguration and partial relocation of our assets.

We expect this reconfiguration to be completed in the second quarter of 2022, and at that time, we will recommence deliveries to the Bogue Power Plant.

• As no volumes were delivered to the Bogue Power Plant, our revenue from the Montego Bay Facility decreased by $7,417 from $18,129 for the three months ended December 31, 2021 to $10,712 for the three months ended March 31, 2022.

Similarly, sales at the Montego Bay Facility decreased by $14,067 from $24,779 for the three months ended March 31, 2021 to $10,712 for the three months ended March 31, 2022.

The San Juan Power Plant completed additional maintenance activities in the first quarter of 2022, leading to lower consumption of natural gas.

Sales at the San Juan Facility decreased by $3,959 from $14,953 for the three months ended December 31, 2021 to $10,994 for the three months ended March 31, 2022.

Sales at the San Juan Facility also decreased by $34,624 for the three months ended March 31, 2022.

Revenue from cargo sales was $285,171 for the three months ended March 31, 2022 as compared to $422,880 for the three months ended December 31, 2021.

For the three months ended March 31, 2021, we did not have any cargo sale transactions in the first quarter of 2021.

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 $63,389 for the three months ended March 31, 2022 and $132,876 for the three months ended December 31, 2021, which was primarily comprised of fixed capacity payments received under CELSE's PPAs.

Revenue recognized from the operation of the Sergipe Power Plant was significantly increased in the fourth quarter of 2021 by emergency dispatch due to poor hydrological conditions in Brazil.

As hydrology conditions have improved in the first quarter of 2022, the Sergipe Power Plant has been dispatched less, reducing revenue from our share of our investment in CELSEPAR

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.

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

Cost of sales increased $134,466 and $196,473 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020,

respectively.

Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $44,581 for the three months ended September 30, 2021,

respectively as compared to the three months ended September 30, 2020.

The increase was primarily attributable to a 15% increase in volumes delivered compared to the three months ended September 30, 2020 and an increase in LNG cost.

weighted-average cost of LNG purchased from third parties increased from $0.37 per gallon ($4.44 per MMBtu) for the three months ended September 30, 2020 to $0.58 per gallon ($6.98 per MMBtu) for the three months ended September 30, 2021.

Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $87,852 for the nine months ended September 30, 2021,

respectively as compared to the nine months ended September 30, 2020.

The increase was primarily attributable to a 42% increase in volumes delivered compared to the nine months ended September 30, 2020 and an increase in LNG cost.

weighted-average cost of LNG purchased from third parties increased from $0.51 per gallon ($6.13 per MMBtu) for the nine months ended September 30, 2020 to $0.54 per gallon ($6.58 per MMBtu) for the nine months ended September 30, 2021.

Cost of LNG from the sale of cargos in the market were $18,191 for the three and nine months ended September 30, 2021 as compared to $0 for the three and nine months ended September 30, 2020.

2021, due to the significant increase in market pricing of LNG, we have used flexibility in our operations and 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 $0.69 per gallon ($8.33 per MMBTU) for the three and nine months ended September 30, 2021.

Subsequent to the acquisition of an interest in the Sergipe Facility as part of the Mergers, our share of Cost of sales from our investment in CELSEPAR was $73,015 and $75,042 for the three and nine months

ended September 30, 2021, respectively, 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 September 30, 2021 and December 31, 2020 was $0.64 per gallon ($7.71 per MMBtu)

and $0.40 per gallon ($4.81 per MMBtu), respectively.

Charter costs decreased Cost of sales by $2,901 for the three months ended September 30, 2021.

As a result of the Mergers, we have effectively settled our charter agreement for the Freeze , one of the acquired vessels, and as such, the decrease in charter costs was attributable to the lower costs associated with the Freeze .

Charter costs increased Cost of sales by $3,441 for the nine months ended September 30, 2021, respectively.

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 .

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 decreased $147,284 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

• The decrease was primarily due to lower cost and volume of LNG cargo sales in the market.

We recognized $86,462 during the three months ended March 31, 2022 to acquire cargos sold to third parties, as compared to $166,027 for the three months ended December 31, 2021.

Due to the significant increase in market pricing of LNG in the second half of 2021 and continued increase in the first quarter of 2022, we have optimized our supply portfolio to sell a portion of our committed cargos in the market.

LNG cargo sales in the market decreased by 6.6 TBtus from 16.3 TBtus for the three months ended December 31, 2021 to 9.7 TBtus for the three months ended March 31, 2022.

The weighted-average cost of LNG from the sale of a portion of our cargos also decreased from $10.20 per MMBtu for the three months ended December 31, 2021 to $8.81 per MMBtu for the three months ended March 31, 2022.

• During the first quarter of 2022, the Sergipe Power Plant was dispatched substantially less than in the fourth quarter of 2021 due to improved hydrology conditions in Brazil.

Our share of cost of sales from our investment in CELSEPAR, which was primarily comprised of LNG costs to fuel the power plant, was $24,742 for the three months ended March 31, 2022, as compared to $100,811 for the three months ended December 31, 2021

• Cost of LNG purchased from third parties for sale to our customers decreased $6,633 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

The decrease was primarily

attributable to a 3% decrease in volumes delivered compared to the three months ended December 31, 2021, and a slight decrease in LNG cost.

The weighted-average cost of LNG purchased from third parties decreased from $9.57 per MMBtu for the three months ended December 31, 2021 to $9.49 per MMBtu for the three months ended March 31, 2022.

Cost of sales increased $138,861 for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021.

• We recognized cost to acquire LNG cargos sold to third parties and our share of cost of sales from our investment in CELSEPAR during the first quarter of 2022, totaling $111,204.

We did not have any cargo sale transactions in the first quarter of 2021, and the acquisition of our investment in CELSEPAR in the Mergers occurred subsequent to March 31, 2021.

Accordingly, the increased costs of sales was primarily driven by these transactions.

• Cost of LNG purchased from third parties for sale to our customers decreased $5,017 for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021.

We delivered 41% less volumes to our terminal customers in the current quarter as compared to the three months ended March 31, 2021.

Our cost of LNG was significantly higher in the current quarter, and as such, the decrease of cost of sales to deliver to our terminal customers did not fully correspond with the decrease in volumes.

The weighted-average cost of LNG purchased from third parties increased from $6.17 per MMBtu for the three months ended March 31, 2021 to $9.49 per MMBtu for the three months ended March 31, 2022.

The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2022 and December 31, 2021 was $8.21 per MMBtu and $9.51 per MMBtu, respectively.

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 $13,569 and $35,481

for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020.

Subsequent to acquisition of an interest in the Sergipe Facility as part of the Mergers, our share of Operations and maintenance from our investment in CELSEPAR was $7,227 and $12,306 for the three and nine

months ended September 30, 2021, respectively, 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.

The increase for the three months ended September 30, 2021 as compared to the three months ended September 30, 2020 was primarily the result of costs of operating the San Juan Facility and CHP Plant and

higher payroll costs, maintenance costs, insurance costs and port fees;

these additional costs were $8,878.

The increase for the nine months ended September 30, 2021 as compared to the nine months ended September 30, 2020 was primarily the result of San Juan Facility and the CHP Facility that were still in

development during a portion of the nine months ended September 30, 2020.

Operations and maintenance increased by the costs of operating the San Juan Facility and CHP Plant of $10,732.

We also incurred $13,092 of payroll costs,

maintenance costs, insurance costs and port fees.

Operations and maintenance increased $5,084 and $13,990 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and March 31, 2021, respectively .

• The increase for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and March 31, 2021 was primarily attributable to higher logistics costs associated with our ISO container distribution system.

In the first quarter of 2022, we continued to source LNG from our Miami Facility to service industrial end users in Jamaica due to the reconfiguration and partial relocation of our assets at the Port of Montego Bay, and we incurred additional costs to distribute LNG to customers via our ISO container distribution system.

• Additionally, the increased costs in the first quarter of 2022 when compared to the first quarter of 2021 was due to the inclusion of our share of Operations and maintenance from our investment in CELSEPAR of $7,074 for the three months ended March 31, 2022, 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 $)

Ended September

Three Months Ended,

(in thousands of $) March 31, 2022 December 31, 2021 Change March 31, 2021 Change

Total revenues 114,942 $ 117,796 $ (2,854) $ — $ 114,942

Cost of sales — — — — —

Vessel operating expenses 25,942 23,000 2,942 — 25,942

Operations and maintenance — — — — —

Segment Operating Margin $ 89,000 $ 94,796 $ (5,796) $ — $ 89,000

Prior to the completion of the Mergers, we reported our results of operations in a single segment;

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 nine months ended September 30, 2021 represents five and a half months of operations .

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.

Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for repositioning vessels as well as the reimbursement of certain vessel operating costs.

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 .

Subsequent to the completion of the Mergers, five of the FSRUs and one LNGCs were on hire under long-term charter agreements for the full period.

Two LNGCs were operating in the spot market for a

portion of the period subsequent to the completion of the Mergers through June 30, 2021.

In the third quarter, one of these LNGCs, 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 in the third quarter of 2021.

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 three and nine months ended September 30, 2021, revenue recognized in the Ships segment

included $11,607 and $21,288 of interest income for the Nanook sales-type

lease and $1,491 and $2,656 of revenue for operating services, respectively, provided to CELSE.

As all operations of the Ships segment were acquired in the Mergers, the results of operations for the Nanook for the nine months ended September 30, 2021 represents

five 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 $26,011 and $47,758 for the three and nine months ended September 30, 2021, respectively, which was primarily comprised of fees received under the long-term tolling arrangement.

The Hilli maintained 100% commercial uptime during the period subsequent to the Mergers.

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

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.

Total revenue

Total revenue for the Ships segment decreased $2,854 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

The decrease was primarily driven by lower revenue as a result of a change in on-hire days quarter over quarter.

The calendar quarter is two days shorter in the first quarter, and as such, revenue decreased slightly due to lower number of commercial on-hire days.

Vessel operating expenses

Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication

expenses and management fees .

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

Vessel operating expenses include 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 three and nine months ended September 30, 2021, we recognized $21,210 and $41,385, respectively, in Vessel operating expenses.

As all operations of the Ships

segment were acquired in the Mergers, Vessel operating expenses for the nine months ended September 30, 2021 represents five and a half months of operations of each of the acquired vessels.

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.

Vessel operating expenses increased $2,942 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021, primarily due to increased customs claims in Jordan where one of our FSRUs operates.

As all operations of the Ships segment were acquired in the Mergers, there were no comparable transactions for the three months ended March 31, 2021.

Other operating results

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands of $)

Three Months Ended,

(in thousands of $) March 31, 2022 December 31, 2021 Change March 31, 2021 Change

Selling, general and administrative $ 48,041 $ 74,927 $ (26,886) $ 33,617 $ 14,424

Transaction and integration costs 1,901 2,107 (206) 11,564 (9,663)

Contract termination charges and loss on mitigation sales

Depreciation and amortization 34,290 30,297 3,993 9,890 24,400

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Interest expense 44,916 46,567 (1,651) 18,680 26,236

Other (income) expense, net

Other (income), net (19,725) (3,692) (16,033) (604) (19,121)

Loss on extinguishment of debt, net — 10,975 (10,975) — —

Net income (loss) before income from equity method investments and income taxes 141,265 165,641 (24,376) (40,386) 181,651

(Loss) income from equity method investments

Tax provision

Income (loss) from equity method investments 50,235 (8,515) 58,750 — 50,235

Tax (benefit) provision (49,681) 5,403 (55,084) (877) (48,804)

Net income (loss) $ 241,181 $ 151,723 $ 89,458 $ (39,509) $ 280,690

Selling, general and administrative

Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors and screening costs associated

with development activities for projects that are in initial stages and development is not yet probable.

Selling, general and administrative increased $19,981 for the three months ended September 30, 2021, as compared to the three months ended September 30, 2020.

The increase was primarily

attributable to $10,558 of higher payroll costs associated with increased headcount for the three months ended September 30, 2021.

Contributing to the increase was higher lease expense, insurance and IT, screening expenses, management fees,

professional services, and other costs attributable to our expanded operations of $6,076.

Selling, general and administrative increased $37,681 for the nine months ended September 30, 2021, as compared to the nine months ended September 30, 2020.

The increase was primarily

attributable to $21,451 of higher payroll costs associated with increased headcount for the nine months ended September 30, 2021.

Contributing to the increase was higher lease expense, insurance and IT, screening expenses, management fees,

professional services, and other costs attributable to our expanded operations of $14,875.

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 decreased $26,886 for the three months ended March 31, 2022, as compared to the three months ended December 31, 2021.

The decrease was primarily attributable to a decrease in share-based compensation expense.

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 also have incurred higher payroll costs, insurance expenses, management fees and professional fees due to the continue expansion of our operations as compared to the fourth quarter of 2021.

Selling, general and administrative increased $14,424 for the three months ended March 31, 2022, as compared to the three months ended March 31, 2021.

The increase was primarily attributable to higher payroll, professional fees and managements fees associated with the continued expansion of our operations.

Transaction and integration costs

Transaction and integration costs decreased $2,180 and increased $38,536 for the three and nine months ended September 30, 2021, as compared to the three and nine months ended September 30, 2020,

respectively.

For the three months ended September 30, 2021, we incurred $1,848 in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs.

For the nine months ended September 30, 2021, we incurred $42,564 for transaction and integration costs.

As part of arranging financing for the Mergers, we incurred $15,000 in bridge financing

commitment fees.

We issued the 2026 Notes to pay for a portion of the consideration for the Mergers and did not utilize the commitments under the bridge financing, and as such, the fees were expensed with the termination of the bridge financing

commitment letter in the second quarter of 2021.

We also incurred $3,978 of costs related to the settlement of a contractual indemnification obligation under a pre-existing lease arrangement prior to the GMLP Merger.

The remaining transaction and

integration costs were incurred in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs.

For the three and nine months ended September 30, 2020, we incurred $4,028 of third-party fees associated with a new credit agreement that was accounted for as a modification.

Contract termination charges and loss on mitigation sales

Loss on mitigation sales for the three and nine months ended September 30, 2020 was $0 and $124,114, respectively.

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 three months ended June 30, 2020.

We terminated our obligation in the second quarter of 2020 to both take

advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs.

Additionally, in the second quarter of 2020, we experienced lower than expected consumption by some of our customers, primarily as a

result of unplanned maintenance at one of our customer’s facilities in Jamaica.

As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of $18,906 on the sale of this cargo that was

recognized during the second quarter of 2020.

We did not have such transactions during the three and nine months ended September 30, 2021.

For the three months ended March 31, 2022, we incurred $1,901 for transaction and integration costs, as compared to $2,107 and $11,564 for the three months ended December 31, 2021 and March 31, 2021, respectively.

For the three months ended March 31, 2021, we incurred transaction and integration costs were incurred in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs.

Our integration costs decreased in both the fourth quarter of 2021 and the first quarter of 2022 as the integration of GMLP and Hygo has progressed since the acquisition date.

Depreciation and amortization

Depreciation and amortization increased $21,705 and $45,717 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30,

Depreciation and amortization increased $3,993 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

For the three months ended March 31, 2022, we incurred higher amortization of favorable and unfavorable contracts acquired in the Mergers as the amortization of certain unfavorable contract liabilities (reduction to expense) was completed in the fourth quarter of 2021.

Depreciation and amortization increased $24,400 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

The increase was primarily due to the following:

• Subsequent to the completion of the Mergers, our results of operations include depreciation expense primarily for the vessels acquired.

We recognized $13,691 and $25,100 of incremental depreciation expense

for the acquired vessels during the three and nine months ended September 30, 2021 as compared to the same periods in the prior year;

Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $6,779 and $12,128 for the three and nine months ended September 30, 2021, respectively;

Increase in depreciation of $427 and $5,229 for the San Juan Facility that went into service in July 2020 for the three and nine months ended September 30, 2021, respectively;

Increase in depreciation of $2,297 for the CHP Plant that went into service in March 2020 for the nine months ended September 30, 2021.

We recognized $14,070 of incremental depreciation expense for the acquired vessels during the three months ended March 31, 2022

• Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $8,346 for the three months ended March 31, 2022.

Interest expense

Interest expense increased by $37,782 and $56,856 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30, 2020.

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 in the second and third quarters of 2021, borrowings

under the Vessel Term Loan Facility and the CHP Facility (all defined below);

principal outstanding on outstanding facilities was $3,888,894 as of September 30, 2021 as compared to total outstanding debt of $1,000,000 as of September 30, 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 condensed 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

For the three months and nine months ended September 30, 2021, we recognized additional interest expense attributable to assumed debt of $15,263 and $8,628, respectively.

Interest expense decreased by $1,651 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021.

The decrease was primarily due to the termination of the sale leaseback agreement of the Eskimo assumed in the Mergers.

Interest expense increased by $26,236 for the three months ended March 31, 2022, as compared to the three months ended March 31, 2021.

The increase was primarily due to an increase in total principal outstanding due to the issuance of the 2026 Notes in April 2021, draws on the Revolving Facility, borrowings under the Vessel Term Loan Facility and the South Power 2029 Bonds (all defined in our Annual Report);

principal balance on outstanding facilities was $3,978,250 as of March 31, 2022 as compared to total outstanding debt of $1,250,000 as of March 31, 2021.

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 $389,946 as of December 31, 2021.

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 condensed consolidated financial statements.

For the three months ended March 31, 2022, we recognized additional interest expense attributable to assumed debt of $3,378.

Other (income) expense, net

Other (income) expense, net increased by $7,969 and $17,637 for the three and nine months ended September 30, 2021, respectively, as compared to the three and nine months ended September 30,

The increase was primarily due to the following::

Gains in investments in equity securities compared to losses in the same periods in 2020, contributing $7,335 and $9,640 for the three and nine months ended September 30, 2021, respectively;

Increase from the reduction in losses resulting from the fair value of derivative liabilities and equity agreement associated with payments due to sellers in asset acquisitions of $2,737 and $3,156, for the

three and nine months ended September 30, 2021, respectively;

Changes in the fair value of the cross-currency interest rate swap and the interest rate swaps acquired in connection with the Mergers, resulting in expense of $4,278 and additional income of $2,081, for

the three and nine months ended September 30, 2021, respectively.

Other (income) expense, net increased by $16,033 and $19,121 for the three months ended March 31, 2022, as compared to the three months ended December 31, 2021 and March 31, 2021, respectively.

Income recognized in the first quarter of 2022 was primarily comprised of the following :

• Changes in the fair value of the cross-currency interest rate swap and the interest rate swaps acquired in connection with the Mergers, resulted in income of $24,409 for the three months ended March 31, 2022.

• Changes in the fair value adjustments for the equity agreement and derivatives related to contingent payments due to sellers in asset acquisitions resulted in additional expense of $2,765 for the three months ended March 31, 2022.

Loss on extinguishment of debt, net

Loss on extinguishment of debt for the three and nine months ended September 30, 2020 was $23,505 and $33,062, respectively, as a result of the extinguishment of previous credit facilities in

January 2020 and September 2020.

We did not have such transactions during the three and nine months ended September 30, 2021.

Loss on extinguishment of debt for the three months 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”) had been consolidated in our financial statements subsequent to the Mergers.

In connection with the termination of this financing arrangement, we recognized a loss on extinguishment of debt based on the difference between the repurchase price under the sale leaseback arrangement and the carrying value of the net assets of the Eskimo SPV upon deconsolidation.

There were no comparable transactions for the three months ended March 31, 2022 or March 31, 2021.

Tax provision

We recognized a tax provision for the three and nine months ended September 30, 2021 of $3,526 and $7,058, respectively, compared to tax provision of $1,836 and $1,949 for the three and nine

months ended September 30, 2020, respectively.

The increases to the tax provision and effective tax rate for both the three and nine months ended September 30, 2021 was primarily driven by an increase in pre-tax income in certain profitable

operations and the inclusion of operations of certain jurisdictions of acquired business.

For the nine months ended September 30, 2021, these increases in tax expense were partially offset by the release of a valuation allowance in a

foreign jurisdiction resulting in a discrete benefit of $1,800.

We recognized a tax benefit for the three months ended March 31, 2022 of $49,681 compared to a tax provision of $5,403 for the three months ended December 31, 2021 and a tax benefit of $877 for the three months ended March 31, 2021.

The increase to the tax benefit and associated decrease to the effective tax rate for the three months ended March 31, 2022 was primarily driven by the remeasurement of a deferred income tax liability in conjunction with an internal reorganization.

Our equity method investment in CELSEPAR is now directly held by a subsidiary domiciled in the United Kingdom;

the investment was previously held by a subsidiary domiciled in Brazil resulting in a discrete tax benefit of $76,460 recognized in the first quarter of 2022.

This increase in benefit for the three months ended March 31, 2022 was partially offset by an increase in pretax income for certain profitable operations, including GMLP and Hygo, for the three months ended March 31, 2022.

The Company has not recorded any material changes in liabilities for uncertain tax positions as of March 31, 2022.

Income from equity method investments

During the period after the completion of the Mergers, we recognized losses and income from our investments in Hilli and CELSEPAR of $(15,983) and $22,958 for the three and nine months ended

September 30, 2021, respectively.

Our proportionate share of the losses and earnings of $(7,101) and $37,614, respectively, were offset by amortization of basis differences through our equity earnings of $8,882 and $14,656 for the three and nine

months ended September 30, 2021, respectively.

During the period after the Mergers, our share of earnings from CELSEPAR was significantly impacted by a foreign currency remeasurement loss of $17,709 for the three months ended September 30, 2021

and a gain of $8,067 for the nine months ended September 30, 2021, primarily as a result of the remeasurement of the Nanook finance lease obligation.

We recognized income (loss) from our investments in Hilli and CELSEPAR of $50,235 for the three months ended March 31, 2022 and $(8,515) for the three months ended December 31, 2021, respectively.

Our share of earnings from CELSEPAR was significantly impacted by a foreign currency remeasurement gain of $42,466, net of applicable statutory rate for the three months ended March 31, 2022 as a result of the remeasurement of the Nanook finance lease obligation, as compared to a remeasurement loss of $(6,788), net of applicable statutory rate for the three months ended December 31, 2021.

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 and do not include all integration and transaction costs expected to be incurred associated with these acquisitions.

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 the Sergipe Facility, a 50% interest in the Sergipe Power Plant, as well as the

Barcarena Facility and the Santa Catarina Facility that are currently in development.

• Our historical financial results include the results of operations of Hygo and GMLP only since the completion of the Mergers in April 2021.

Upon completion of the Mergers, we acquired a fleet of seven FSRUs, six LNG carriers and an interest in a floating liquefaction vessel.

We also acquired a 50% interest in the Sergipe Facility and the Sergipe Power Plant, as well as the Barcarena Facility and Barcarena Power Plant and the Santa Catarina Facility that are currently in development.

The results of operations of Hygo and GMLP began to be included in our financial statements upon the closing of the acquisitions on April 15, 2021.

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

Our historical financial results do not include significant projects that have

recently been completed or are near completion.

Our results of operations for the three and nine months ended September 30, 2021 include our Montego Bay Facility, Old Harbour

Facility, San Juan Facility, certain industrial end-users and our Miami Facility.

We are finalizing development of our La Paz Facility and 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, the Barcarena Facility, the Santa Catarina Facility and the Ireland Facility.

Our historical financial results do not reflect new LNG supply agreements that

will lower the cost of our LNG supply through 2030.

We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from

third parties for the three and nine months ended September 30, 2021, respectively, a significant portion of which is under an LNG supply agreement signed in 2018.

During 2020 and 2021, we also 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.

Our results of operations after the acquisitions also included 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 three months ended March 31, 2022 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility.

We recently placed a portion of our La Paz Facility into service, and in the fourth quarter of 2021, our revenue and results of operations began to be impacted by operations in Mexico.

We are continuing to develop of our La Paz Power Plant and our Puerto Sandino Facility, and our current results do not include revenue and operating results from these projects.

Our current results also exclude other developments, including the Suape Facility, Barcarena Facility, Santa Catarina Facility and Ireland Facility.

• Our historical financial results do not reflect new LNG supply agreements, as well as our Fast LNG solution that will lower the cost of our LNG supply.

We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 94% of our LNG volumes from third parties for the three months ended March 31, 2022.

We have entered into LNG supply agreements at a price indexed to Henry Hub through 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement.

We have entered into supply agreements to secure supply of 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;

pricing under these agreements is indexed to Henry Hub, resulting in expected pricing below our historical supply agreements.

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 used flexibility in our operations and supply portfolio to sell a portion of our

committed cargos in the market with delivery in Q4 2021, and these cargo sales are expected to increase our revenues and results of operations in the fourth quarter of 2021.

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 throughout 2022, and these cargo sales are expected to increase our 2022 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 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.

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, most recently as

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

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

We have historically funded our developments through proceeds from our IPO and debt and equity financing, most recently as follow s (below terms defined in our Annual Report):

• 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 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.

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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

$1,663 million, with approximately $1,154 million having already been spent through September 30, 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, proceeds from the financing of the CHP Plant and borrowings under our Revolving Facility.

in February 2022, we expanded capacity under the Revolving Facility to $315,000.

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

In January 2022, we agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds.

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.

Through the first quarter of 2022, we have received proceeds of $175,783 from the issuance of South Power 2029 Bonds.

• In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility.

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 $2,080 million, with approximately $1,584 million having already been spent through March 31, 2022.

This estimate represents the committed expenditures for our Fast LNG project, as well as committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, the Suape Facility, the Barcarena Facility, Santa Catarina Facility and the Sri Lanka Facility.

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 September 30, 2021, we have spent

approximately $ 128 million to develop the Pennsylvania Facility.

Approximately $22 million of construction and development costs have been expensed as we have not issued a final notice to

proceed to our engineering, procurement and construction contractors.

Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106 million, has been

capitalized, and to date, we have repurposed approximately $17 million of engineering and equipment to our Fast LNG project.

The following table summarizes the changes to our cash flows for the nine months ended September 30, 2021 and 2020, respectively:

Nine Months Ended September 30,

(in thousands)

Cash flows from:

Operating activities

Investing activities

Financing activities

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

Cash used in operating activities

Our cash flow used in operating activities was $139,687 for the nine months ended September 30, 2021, which increased by $23,977 from $115,710 for the nine months ended September 30, 2020.

net loss for the nine months ended September 30, 2021, when adjusted for non-cash items, decreased by $111,484 from the nine months ended September 30, 2020.

The reduction to the net loss was offset by changes in working capital accounts,

primarily significant increases in receivables, inventory and accrued liabilities, including costs attributable to the Mergers.

Cash used in investing activities

Our cash flow used in investing activities was $2,031,158 for the nine months ended September 30, 2021, which increased by $1,915,454 from $115,704 for the nine months ended September 30, 2020.

Cash used for the Mergers, net of cash acquired was $1,586,042.

Cash outflows for investing activities during the nine months ended September 30, 2021 were also used for continued development of the Puerto Sandino Facility, Suape Facility,

Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution.

During the nine months ended September 30, 2020, we completed the CHP Plant and were in the final stages of development of the San Juan Facility, and as such, we incurred lower cash outflows

for investing activities for the nine months ended September 30, 2020.

Cash provided by financing activities

Our cash flow provided by financing activities was $1,874,149 for the nine months ended September 30,

2021, which increased by $1,582,333 from cash provided by financing activities of $291,816 for the nine months ended September 30, 2020.

Cash provided by financing activities during the nine months ended September 30, 2021 was due to proceeds

received from the borrowings under the 2026 Notes of $1,500,000, the draw of $200,000 on the Revolving Facility, and the draw of $430,000 million on the Vessel Term Loan Facility.

The proceeds received were further offset by financing fees paid

in connection with the borrowings, tax payments for equity compensation made on behalf of employees and dividends paid for the nine months ended September

Cash flow provided by financing activities during the nine months ended September 30, 2020 were primarily consisted of proceeds received from the borrowings under the 2025 Notes of $1,000,000 and

the borrowings under our previous credit agreement of $800,000, partially offset by an original issue discount of $20,000 and financing fees.

Additionally, the remaining proceeds from secured bonds issued in Jamaica of $52,144 were received

during the first quarter of 2020.

A portion of these proceeds was used to fund the repayment of our previous credit agreement of $800,000, the senior secured and unsecured bonds that had been issued in Jamaica of $183,600, and our previous term

loan facility of $506,402.

Long-Term Debt and Preferred Stock

On September 2, 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 condensed 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, the Company recorded $4,028 of third-party fees as an expense in the condensed consolidated statements of operations and comprehensive loss.

On December 17, 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 September 30, 2021 and December 31,

2020, remaining unamortized deferred financing costs for the 2025 Notes was $9,323 and $10,439, respectively.

On April 12, 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 GMLP Merger and pay related fees and expenses.

In connection with the issuance of the 2026 Notes, we incurred

$24,588 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the condensed consolidated balance sheets.

As of September 30, 2021, total remaining unamortized deferred

financing costs for the 2026 Notes was $22,362.

Vessel Term Loan Facility

On September 18, 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the “Vessel Term Loan Facility”).

Under this facility,

the Company borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels.

Loans under the Vessel Term Loan Facility bear interest at a rate of LIBOR plus a margin of 3 percent.

The Vessel Term Loan Facility shall be repaid in quarterly installments of $15,357, with

the final repayment date in September 2024.

Quarterly principal payments will be increased to reflect any upsize of the Vessel Term Loan Facility to reflect a straight-line amortization profile over the remaining term.

Obligations under the Vessel Term Loan Facility are guaranteed by GMLP and certain of GMLP’s subsidiaries.

Lenders have been granted a security interest covering three floating storage and

regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security.

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 September 30, 2021.

In connection with the closing the Vessel Term Loan Facility, we incurred $6,229 in origination, structuring and other fees, which were deferred as a reduction of the principal balance of the

Vessel Term Loan Facility on the condensed consolidated balance sheets.

As of September 30, 2021, total remaining unamortized deferred financing costs for the Vessel Term Loan Facility was $6,161.

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 255.6 million ($45

million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debenture Loan”).

The Debenture Loan was recognized at fair value of $44,566 on the date of the 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.

On August 3, 2021, NFE South Power Holdings Limited, a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”).

We initially drew $100,000 under the CHP Facility, and

the CHP Facility is secured by our combined heat and power plant in Clarendon, Jamaica.

We incurred $3,651 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 condensed consolidated balance sheets.

As of September 30, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $3,636.

Revolving Facility

On April 15, 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 subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially

the same collateral as 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.

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 September 30,

We incurred $3,974 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 condensed consolidated

balance sheets.

As of September 30, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $3,658.

During the second and third quarters of 2021, the Company drew $152,500 and $47,500 on the Revolving Facility, respectively.

During the third quarter of 2021, the Company repaid the amounts

outstanding on the Revolving Facility, and as of September 30, 2021, no amounts remain outstanding.

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 condensed consolidated financial statements.

The SPVs service the

loan facilities through payments made by us under the sale leaseback arrangements.

The SPV loans and the sale leaseback arrangements assumed in the Mergers contain certain operating and financing restrictions and covenants that require:

(a) certain subsidiaries to maintain a

minimum level of liquidity of $30,000 and consolidated net worth of $123,950, (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of

6.5:1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110% and 120%, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of

less than 0.70:1.

As of September 30, 2021, the Company was in compliance with all covenants under debt and lease agreements.

Eskimo Leaseback and Credit Facility

As part of the Mergers, we have assumed obligations under a sale and leaseback of the Eskimo with Sea 23 Leasing Co.

Limited of China

Merchants Bank Leasing (the “Eskimo Leaseback”).

Payments are due monthly in 120 installments of $1,069 along with amounts owed for interest of LIBOR plus 3.85%, with a balloon payment of $128,250 due upon maturity.

Sea 23 Leasing Co.

Limited , the owner of the Eskimo , has a long-term loan facility that is denominated in USD, has a loan term of ten years and bears 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 on the date of the Mergers.

The discount recognized in purchase accounting will

result in additional interest expense until maturity.

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”).

are due quarterly in 48 installments of $2,943 along with amounts owed for interest due based on LIBOR plus 3.5%, with a balloon payment of approximately $94,000 upon maturity.

Compass Shipping 23 Corporation Limited, the owner of the Nanook , has a long-term loan facility that is denominated in USD, has a loan term of twelve years, bears interest at

a fixed rate of 2.7% (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 over a term of

approximately six years 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 at maturity 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.

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 condensed

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

As of September 30, 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)

interest rate

927.7($171.4)

Inter-American Development Bank

766.9($141.7)

IDB Invest (1)

IDB China Fund

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 September 30, 2021, the balance of the CELSE Debentures was R$3,324.02 million ($614.0 million as of September 30, 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

(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.

On July 2, 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 NFE Power Brasil Participações S.A (“NFE Brazil”), each as sponsor (the “GE Credit Facility”).

Pursuant to the GE Credit Facility, GE Capital agreed to provide $120,000 in credit support in respect of CELSEPAR’s obligation to make certain

contingent equity contributions to CELSE.

Amounts disbursed under the GE Credit Facility accrue interest at a fixed rate of LIBOR plus a margin of 11.4% and are payable on May 30 and November 30 each year, beginning on May 30, 2020.

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.

On July 9, 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

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.

On July 9, 2021, a standby letter of credit was

issued under this facility for the benefit of CELSE pursuant to the working capital facility in an amount of $31.1 million with an expiration date of September 15, 2021.

The standby letter of credit is guaranteed, jointly but not severally, by

CELSE’s shareholders, NFE and Electricidade do Brasil S.A.—Ebrasil.

Golar Hilli Leaseback

As part of the Mergers, we acquired an investment in Hilli LLC;

Golar Hilli Corporation (“Hilli Corp”), is a direct subsidiary of Hilli LLC.

and is a party to a Memorandum of Agreement with Fortune Lianjiang Shipping

S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the

“Hilli Leaseback”).

Under the Hilli Facility, Hilli Corp pays Fortune equal quarterly principal payments plus interest based on LIBOR plus a margin of 4.15%.

Our 50% share of Hilli Corp’s indebtedness

of $729,000 amounted to $364,500 as of September 30, 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:

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

On July 16, 2021, the Company entered into an uncommitted letter of credit and reimbursement agreement with a bank for the issuance of letters of credit for an aggregate amount of up to $75,000.

Outstanding letters

of credit are subject to a fee of 1.75% to be paid quarterly, and interest is payable on the principal amounts of unreimbursed letter of credit draws under the facility at a rate of the higher of the bank’s prime rate or the Federal Funds

Effective Rate plus 0.50% and a margin of 1.75%.

We are using this uncommitted letter of credit and reimbursement agreement to reduce the cash collateral required under existing letters of credit releasing restricted cash.

A portion of our

restricted cash balance supports existing letters of credit, and this uncommitted letter of credit and reimbursement agreement has replaced these letters of credit and released restricted cash, enhancing our ability to manage the working capital

needs of the business.

Off Balance Sheet Arrangements

As of September 30, 2021 and December 31, 2020, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating

As of March 31, 2022, we have spent approximately $128 million to develop the Pennsylvania Facility.

Approximately $22 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors.

Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106 million, has been capitalized, and to date, we have repurposed approximately $17 million of engineering and equipment to our Fast LNG project.

Our current air permit required to construct the Pennsylvania Facility is expected to expire in July 2022.

We intend to apply for an updated air permit for the Pennsylvania Facility with the aim of obtaining this permit to coincide with the commencement of construction activities.

Contractual Obligations

1 unchanged sentence

The following table summarizes certain contractual obligations in place as of December 31, 2021.

(in thousands)

There were no material changes to our contractual obligations in the first quarter 2022.

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

Long-term debt obligations $ 4,936,353 $ 305,575 $ 878,471 $ 3,341,677 $ 410,630

1 unchanged sentence

Lease obligations 420,329 67,131 101,295 68,393 183,510

Total $ 10,622,038 $ 1,156,766 $ 2,617,549 $ 4,860,887 $ 1,986,836

Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled

maturities, and interest rates in effect as of December 31, 2020.

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.

In 2021, we amended one of these supply agreements to increase our total commitment through 2030 to 601 TBtus at a price

indexed to Henry Hub.

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

We are 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

Fixed lease payments for short-term leases are also included in the table above.

Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table.

Fixed lease payments for

short-term leases are also included in the table above.

Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease.

The Company currently has seven vessels under time charter leases with non-cancellable terms ranging from three months to four 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.

As of December 31, 2021, the Company had 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 seven 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.

Terms for leases of port space range from 20 to 25 years.

The land site lease is held with an affiliate of the Company and has a remaining term of approximately five years with an automatic renewal term of five years for up to an additional 20 years.

During 2020, we executed multiple lease agreements for the use of ISO tanks, and we began to receive these ISO tanks and the lease terms commenced during the second quarter of 2021.

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.

Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated

financial statements and the accompanying notes.

Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Management evaluates its estimates and related

assumptions regularly and will continue to do so as we further grow our business.

We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more

significant areas involving management’s judgments and estimates.

Revenue recognition

Terminals and infrastructure

Within the Terminals and Infrastructure segment, our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and

steam, which are outputs from our natural gas-fueled infrastructure.

The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer.

The customers consume the

benefit of the natural gas, power and steam when they are delivered to the customer’s power generation facilities or interconnection facility.

Natural gas, power and steam qualify as a series with revenue being recognized over time using an

output method, based on the quantity of natural gas, power or steam that the customer has consumed.

LNG is typically delivered in containers transported by truck to customer sites.

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 has elected not to separate the lease component.

The lease component of such operating leases is recognized as Operating revenue in the condensed

consolidated statements of operations and comprehensive 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 condensed 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 condensed consolidated statements of operations and comprehensive loss.

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 condensed

consolidated statements of operations and comprehensive loss.

The principal component of the lease payment is reflected as a reduction to the net investment in the lease.

In addition to the revenue recognized from the finance lease components of agreements with customers, Other revenue includes revenue recognized from the construction, installation and

commissioning of equipment, inclusive of natural gas delivered for the commissioning process, to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled

power generation facilities.

Revenue from these development services is recognized over time as we transfer control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities

until such time that the customer has declared such conversion services have been completed.

If the customer is not able to obtain control over the asset under construction until such services are completed, revenue is recognized when the

services are completed and the customer has control of the infrastructure.

Such agreements may also include a significant financing component, and we recognize revenue for the interest income component over the term of the financing as Other

The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities.

Receivables represent unconditional rights to consideration;

unbilled amounts typically result from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer.

Contract assets are comprised of the transaction price allocated to completed performance obligations that

will be billed to customers in subsequent periods.

Both unbilled receivables and contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the condensed consolidated balance sheets.

Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed consolidated balance sheets.

Shipping and handling costs are not considered to be separate performance obligations.

All such shipping and handling activities are performed prior to the customer obtaining control of the LNG

or natural gas.

We collect sales taxes from our customers based on sales of taxable products and remits such collections to the appropriate taxing authority.

We have elected to present sales tax collections in

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

The principal component of the lease payment is reflected as a reduction to the net investment in the lease.

Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the condensed

consolidated statements of operations and comprehensive 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 condensed 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 condensed consolidated statements of operations and comprehensive loss over the lease term.

The Company’s 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.

The Company is primarily responsible for fulfilling the performance obligations in the time charters of

vessels owned by the Company, and the Company is the principal in such time charters.

Revenue and expenses for charters of 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 condensed consolidated statements of operations and comprehensive loss.

Our allocation of our share of the net revenues earned from the other pool

participants’ vessels, which may be either income or expense depending on the results of all pool participants, is reflected on a net basis within Vessel operating expenses in the condensed consolidated statements of operations and

comprehensive loss.

Impairment of long-lived assets

We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

Indicators may

include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a

long-lived asset, early termination of a significant customer contract, or the introduction of newer technology.

We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.

Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG.

Our costs to transport and store

LNG are based upon our customer’s contractual commitments once their assets are fully operational.

We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts.

Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets.

These projects are

subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.

Our long-term, take-or pay contracts to deliver natural gas or LNG to our customers also limit our exposure to fluctuations in natural gas and LNG as our pricing is largely based on the Henry

Hub index plus a contractual spread.

Based on the long-term nature of our contracts and the market value of the underlying assets, changes in the price of LNG do not indicate that a recoverability assessment of our assets is necessary.

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, including Fast LNG and

our expanded delivery logistics chain in the Pennsylvania Facility.

We have also considered the impacts of the ongoing COVID-19 pandemic, including the restrictions that governments may put in place and the resulting direct and indirect economic impacts on our

current operations and expected development budgets and timelines.

We primarily operate under long-term contracts with customers, including long-term charter contracts acquired in the Mergers and many of which contain fixed minimum volumes that

must be purchased on a “take-or-pay” basis, even in cases when our customer’s consumption has decreased.

We have not changed our payment terms with customers, and there has not been any deterioration in the timing or volume of collections.

Based on the essential nature of the services we provide to support power generation facilities, our operations and development projects have not been significantly impacted by responses to the

COVID-19 pandemic to date.

We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicators that a recoverability assessment for our assets should be

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 third quarter 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.

During periods of declining 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.

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.

During dramatic increases of LNG prices in recent months, we have been able to take advantage of flexibility in our operations and supply portfolio to sell a portion of our committed cargos in the market with delivery in Q4 2021, and these cargo sales are expected to increase our revenues and

results of operations in the fourth quarter of 2021.

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.

the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge.

Management develops the assumptions used in the recoverability assessment based on

active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.

Share-based compensation

We estimate the fair value of RSUs and performance stock units (“PSUs”) granted to employees and non-employees on the grant date based on the closing price of the underlying shares on the grant

date and other fair value adjustments to account for a post-vesting holding period.

These fair value adjustments were estimated based on the Finnerty model.

As of September 30, 2021, 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.

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

To qualify as a business without outputs, the acquired assets would require an organized workforce with the necessary skills, knowledge and experience that performs a substantive process.

For acquisitions that are not deemed to be businesses, the assets acquired are recognized based on their cost to us as the acquirer, and no gain or loss is recognized.

The cost of assets acquired

in a group is allocated to individual assets within the group based on their relative fair values and no goodwill is recognized.

Transaction costs related to acquisition of assets are included in the cost basis of the assets acquired.

We account for acquisitions that qualify as business combinations by applying the acquisition method.

Transaction costs related to the acquisition of a business are expensed as incurred and

excluded from the fair value of consideration transferred.

Under the acquisition method of accounting, the identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity are recognized and measured at their

estimated fair values.

The excess of the fair value of consideration transferred over the fair values of identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity, net of fair value of any previously

held interest in the acquired entity, is recorded as goodwill.

The Company performs valuations of assets acquired, liabilities assumed and noncontrolling interests in

an acquired entity and allocates the purchase price to its respective assets, liabilities and noncontrolling interests.

Determining the fair value of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity

requires management to use significant judgment and estimates, including the selection of appropriate valuation methodologies, estimates of projected revenues, costs and cash flows, 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 assets, adjusting for age and condition.

Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable.

As a result, actual results

may differ from these estimates.

During the measurement period, the Company may record adjustments to acquired assets, liabilities assumed and noncontrolling interests, with corresponding offsets to goodwill.

Upon the conclusion of a

measurement period, any subsequent adjustments are recorded to earnings.

We use estimates, assumptions and judgments when assessing the recoverability of goodwill.

We test for impairment on an annual basis, or more frequently if a significant event of circumstance

indicates the carrying amounts may not be recoverable.

The assessment of goodwill for impairment may initially be performed based on qualitative factors to determine if it is more likely than not that the fair value of the reporting unit to which

the goodwill is assigned is less than the carrying value.

If so, a quantitative assessment is performed to determine if an impairment has occurred and to measure the impairment loss.

The lease term for each of these leases is five years and expected payments under these lease agreements have been included in the above table.

Office space includes space shared with affiliated companies in New York, as well as offices in Miami, New Orleans, and Rio de Janeiro, which have lease terms between three to seven years.

The following table summarizes the changes to our cash flows for the three months ended March 30, 2022 and March 31, 2021, respectively :

Three Months Ended March 31,

(in thousands) 2022 2021 Change

Cash flows from:

Operating activities $ 114,382 $ (111,986) $ 226,368

Investing activities (189,221) (90,257) (98,964)

Financing activities 36,836 (47,891) 84,727

Net (decrease) in cash, cash equivalents, and restricted cash $ (38,003) $ (250,134) $ 212,131

Cash provided by operating activities

Our cash flow provided by operating activities was $114,382 for the three months ended March 31, 2022, which increased by $226,368 from cash used in operating activities of $111,896 for the three months ended March 31, 2021.

Our net income for the three months ended March 31, 2022, when adjusted for non-cash items, increased by $180,828 from the three months ended March 31, 2021.

Changes in working capital accounts, primarily increases in accounts payable and accrued liabilities, also contributed to additional cash provided by operating activities.

Cash used in investing activities

Our cash flow used in investing activities was $189,221 for the three months ended March 31, 2022, which increased by $98,964 from cash used in investing activities of $90,257 for the three months ended March 31, 2021.

Cash outflows for investing activities during the three months ended March 31, 2022 were also used for continued development of our Fast LNG solution, Santa Catarina Facility, Barcarena Facility, as well as expenditures to complete our La Paz Facility and Puerto Sandino Facility.

Cash outflows for investing activities during the three months ended March 31, 2021 were primarily used for development projects in Nicaragua and Mexico.

Cash provided by financing activities

Our cash flow provided by financing activities was $36,836 for the three months ended March 31, 2022, which increased by $84,727 from cash used in financing activities of $47,891 for the three months ended March 31, 2021.

Cash provided by financing activities during the three months ended March 31, 2022 was due to proceeds from issuance of debt of $200,836, offset by repayments of debt of $123,669 and payment of dividends of $23,773.

Cash flow used in financing activities during the three months ended March 31, 2021 was due to payments of $29,564 related to tax withholdings for share-based compensation, as well as dividends paid of $17,657.

Long-Term Debt and Preferred Stock

The terms of our debt instruments and associated obligations have been described in our Annual Report.

There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below.

South Power 2029 Bonds

In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100,000.

The CHP Facility was secured by a mortgage over the lease of the site on which our CHP Plant is located and related security.

In January 2022, 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 the first quarter of 2022, South Power issued $75,783 of South Power 2029 Bonds for a total amount outstanding of 175,783 as of March 31, 2022.

The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and mature seven years from the closing date of the final tranche.

No principal payments will be due until 2025.

We expect that beginning in May 2025, principal payments will be due on a quarterly basis.

Interest payments on outstanding principal balances will be due quarterly.

Principal payments and interest payments on the South Power 2029 Bonds are guaranteed by NFE.

South Power will be required to comply with certain financial covenants as well as customary affirmative and negative covenants.

The South Power 2029 Bonds also provides for customary events of default, prepayment and cure provisions.

In conjunction with obtaining the CHP Facility, we incurred $3,243 in origination, structuring and other fees.

The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds;

additional fees associated with such lenders of $258,000 were recognized as expense in the first quarter of 2022.

Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the condensed consolidated balance sheets.

As of March 31, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $5,527 and $3,180, respectively.

Debt and lease restrictions

The VIE loans and certain lease agreements with customers assumed in the Mergers contain certain operating and financing restrictions and covenants that require:

(a) certain subsidiaries to maintain a minimum level of liquidity of $30,000 and consolidated net worth of $123,950, (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110% and 120%, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of less than 0.70:1.

As of March 31, 2022, the Company was in compliance with all covenants under debt and lease agreements.

Financial covenants under GMLP's Vessel Term Loan Facility include requirements that GMLP and the borrowing subsidiary 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 million, each as defined in the Vessel Term Loan Facility.

GMLP was in compliance with these covenants as of March 31, 2022 .

The Company is also required to comply with covenants under the Revolving Facility and letter of credit facility, including 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.

The Company was in compliance with all covenants as of March 31, 2022.

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, and the debt obligations of these entities are not reported separately in our consolidated financial statements.

The key terms of CELSEPAR's and Hilli LLC's debt obligations are summarized in our Annual Report.

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.

Standby letters of credit are guaranteed, jointly but not severally, by CELSE’s shareholders, NFE and Ebrasil.

The working capital facility is in an aggregate amount of up to $200.0 million (or its equivalent in Reais).

The facility has a term of 12 months, renewable for equal periods by mutual agreement of the parties.

Amounts disbursed under the working capital facility accrue interest at a rate referenced to Libor+, and contractual margins.

As of March 31, 2022, there were no standby letters of credit issued under this facility.

Off Balance Sheet Arrangements

As of March 31, 2022 and December 31, 2021, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results .

Critical Accounting Policies and Estimates

A complete discussion of our critical accounting policies and estimates is included in our Annual Report for the year ended December 31, 2021.

There have been no significant changes in our critical accounting policies and estimates in the current year.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see “Note 3.

Adoption of new and revised standards” to our notes to condensed consolidated financial statements included elsewhere in

this Quarterly Report.

Adoption of new and revised standards” to our notes to condensed consolidated financial statements included elsewhere in this Quarterly 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-Q

Item 2. Management’s Discussion and Analysis