What changed in this filing

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Item 2. Management’s Discussion and Analysis

2025-06-30 compared with 2024-11-12 · 343 added, 475 removed, 261 unchanged (76% of the section changed)

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Unless otherwise indicated, dollar amounts are presented in millions.

Unless the context indicates otherwise, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc.

Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc.

and its subsidiaries.

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We discuss this important goal in more detail in our Annual Report, “Items 1 and 2:

Business and Properties” under “Sustainability—Toward a Very-Low Carbon Future.”

Business and Properties” under “Sustainability—Toward a Low Carbon Future.”

Our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships.

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

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

We expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." Our first FLNG facility began producing LNG in July 2024.

The first full cargo was loaded onto the Energos Princess vessel and set sail for Europe on September 30, 2024.

Following the anticipated sale of our Miami Facility, we expect to continue sourcing LNG from third parties and for a portion of our supply to be generated by our first FLNG unit.

The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations.

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 fleet.

Our Ships segment includes all vessels which are leased to customers under long-term arrangements.

Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.

We currently source LNG from long-term supply agreements with third-party suppliers.

We placed our first floating liquefaction unit, which we refer to as "Fast LNG" or "FLNG", into service in the fourth quarter of 2024, and we plan to source a portion of our LNG needs from this facility.

The Terminals and Infrastructure segment includes all terminal operations in Jamaica (prior to the sale of our Jamaica Business (as defined below)), Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations.

We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal, logistics or sub-charter operations, which allows us to optimally manage our LNG supply and fleet.

Our Ships segment includes certain vessels which are currently chartered under long-term arrangements to third parties and are part of the Energos Formation Transaction (defined below).

Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire, and these vessels are expected to be included in our Terminals and Infrastructure segment at such time.

In March 2025, we entered into an equity and asset purchase agreement (the "EAPA") to sell our Jamaica business, including operations at the LNG import terminal in Montego Bay, the offshore floating storage and regasification terminal in Old Harbour and the 150 megawatt Combined Heat and Power Plant in Clarendon, along with the associated infrastructure (the "Jamaica Business") for cash consideration of approximately $1.06 billion, subject to certain purchase

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price adjustments.

On May 14, 2025, we completed the sale of the Jamaica Business and received net proceeds of approximately $678 million, with additional $99 million proceeds held in escrow and to be returned to the Company on the release dates as stated in the EAPA.

Our Current Operations – Terminals and Infrastructure

Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, the Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility, 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, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, and Jamalco, a bauxite mining and alumina producer in Jamaica, prior to the sale of the Jamaica Business, as well as the Puerto Rico Electric Power Authority (“PREPA”) and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility, 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.

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 ("Bogue Power Plant").

Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 60,000 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 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 agreement.

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

The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers.

San Juan Facility

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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, industrial end-user customers in Puerto Rico, and after being awarded a new gas sale agreement in the first quarter of 2024, PREPA's gas-fired power plants throughout the island of Puerto Rico.

In the first and second quarters of 2023, we entered into agreements for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas.

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 industrial end-user customers in Puerto Rico.

In 2023, we entered into agreements for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas.

Our customer was contracted by the U.S.

Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid.

We commissioned 150MW of duel-fuel power generation using our gas supply in the second quarter of 2023, and the remaining 200MW was commissioned in September 2023.

In March 2024, o ur contract to provide emergency power services to support the grid stabilization project was terminated.

We are pursuing a $659 million request for equitable adjustment related to the early termination of our contract.

We commissioned 350MW of duel-fuel power generation using our gas supply in less than 180 days.

In March 2024, our contract to provide emergency power services to support the grid stabilization project was terminated, and we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA.

We were also awarded a gas sale agreement with PREPA to supply up to 80 TBtu annually to PREPA's gas-fired power plants, including to the turbines that were sold to PREPA.

The contract initially has a one year term that is renewable annually for three additional annual periods.

In March 2025, the agreement was amended to extend the term by 100 days to June 2025.

We are pursuing a $659 million request for equitable adjustment related to the early termination of our contract to provide emergency power services.

The actual amount of any such adjustment and the timing of any related payments may be materially different than management’s current estimate.

As a result, the Company cannot offer any assurance as to the actual amount that may be recovered pursuant to such request or subsequent claim, if any.

As the outcome of this process is uncertain, we have not recognized any revenue associated with the close out of our contract.

In March 2024, we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA under an Asset Purchase Agreement ("APA").

The purchase price was $306.6 million, and the APA includes an option for PREPA to purchase three additional turbines for additional purchase price of $65.7 million.

We recognized a loss of $77.5 million in Loss on sale of assets, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

In the first quarter of 2024, we were also awarded a new gas sale agreement with PREPA to supply up to 80 TBtu annually to PREPA's gas-fired power plants, including to the turbines that were sold pursuant to the APA.

The contract initially has a one year term that is renewable annually for three additional annual periods.

In the first quarter of 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-Year contract for the operation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and

improving reliability of power generation in Puerto Rico.

In 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-year contract for the operation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and improving reliability of power generation in Puerto Rico.

We receive an annual management fee and are eligible for performance-based incentive fees.

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In the third quarter of 2024, we executed a 10-year gas sales agreement to supply natural gas to additional CFE facilities on take-or-pay basis.

Miami Facility

Our Miami Facility began operations in April 2016.

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.

On June 30, 2024, the Company entered into a definitive agreement to sell its Miami Facility for $62 million.

The transaction is expected to close in the fourth quarter of 2024 subject to customary terms and conditions.

Santa Catarina Facility

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We placed our Santa Catarina Facility in service in the fourth quarter of 2024.

The Santa Catarina Facility is located on the southern coast of Brazil and consists of an FSRU with a processing capacity of approximately 500,000 MMBtu from LNG per day and LNG storage capacity of up to 138,000 cubic meters.

We have developed and constructed a 33-kilometer, 20-inch pipeline that connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A.

(“TBG”) pipeline via an interconnection point in the municipality of Garuva.

The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day of natural gas.

In August 2024, we acquired 100% of the outstanding equity interest of Usina Termeletrica de Lins S.A.

("Lins"), which owns key rights and permits to develop a natural gas-fired power plant for up to 2.05GW located in the State of Sao Paulo, within the city limits of Lins.

We expect to participate in the power auctions anticipated to occur in 2025 in Brazil, and to the extent that NFE is successful in these auctions, we plan to develop a gas-fired power plant using natural gas from the Santa Catarina Facility.

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 ("Bogue Power Plant").

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

We no longer own the Montego Bay Facility after we completed the sale of the Jamaica Business, and starting in the second quarter of 2025, we will no longer reflect the results of operations from the Montego Bay Facility in our financial statements.

Old Harbour Facility

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 agreement.

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

The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers.

We no longer own the Old Harbour Facility and CHP Plant after we completed the sale of the Jamaica Business, and starting in the second quarter of 2025, we will no longer reflect the results of operations from the Old Harbour Facility and CHP Plant in our financial statements.

Our LNG Supply and Cargo Sales

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1) our current contractual supply commitments;

2) additional LNG supply contracts expected to commence in 2027;

and 3) supply from our own Fast LNG production.

We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility.

2) our own FLNG production;

and 3) additional LNG supply contracts expected to commence in 2027.

Our first FLNG facility began to produce LNG in July 2024, and we expect to generate up to 70 TBtu annually from this facility.

When expected production from FLNG is combined with our commitments to purchase and receive physical delivery of LNG volumes, we expect to have sufficient supply for 100% of our committed volumes for each of our downstream terminals inclusive of our San Juan Facility, La Paz Facility, Barcarena Facility and Santa Catarina Facility.

Additionally, we have binding contracts for LNG volumes from two separate U.S.

LNG facilities, each with a 20-year term, which are expected to commence in 2027.

Finally, we plan to source production from our own Fast LNG facilities, the first of which began to produce LNG in July 2024 .

We sold the first full cargo from this facility on September 30, 2024.

We plan to expand that capacity when additional Fast LNG units come online.

Natural gas and LNG markets have experienced unprecedented price volatility in recent years.

LNG facilities, each with a 20-year term, which are expected to commence in 2027 and 2029.

Geopolitical events have substantially impacted and may continue to impact the natural gas and LNG markets, which have experienced significant volatility in recent years.

The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread.

We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component.

Additionally, with our own Fast LNG production, we plan to further mitigate our exposure to variability in LNG prices.

In 2022 and 2023, our revenue and results of operations benefited from selling cargos into the global LNG market.

As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.

Additionally, with our own Fast LNG production, we plan to further mitigate our exposure to variability in LNG prices, and our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.

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Our Current Operations – Ships

Our Ships segment includes Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are leased to customers under long-term arrangements.

At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and described in more detail below, we plan to charter these vessels for our own operational purposes.

The results of operations of vessels utilized in our terminal operations are reflected in the Terminals and Infrastructure segment.

Our shipping assets include Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs").

Our shipping assets are included in both of our operating segments.

Certain vessels are currently chartered to third parties under long-term arrangements and are part of the Energos Formation Transaction (defined below);

such vessels are included in our Ships segment.

At the expiration of third party charters of these vessels, we plan to utilize these vessels for our own operational purposes.

Vessels we operate at our terminal operations or that we decide to sub-charter are included in our Terminals and Infrastructure segment.

In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of eleven vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos.

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The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback.

As a result, these ten vessels continue to be recognized on our Consolidated Balance

Sheet as Property, plant and equipment, and the proceeds are recognized as debt.

As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheet as Property, plant and equipment, and the proceeds are recognized as debt.

Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue;

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our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”);

our LNG terminal (“Barcarena Facility”) and power plants (“Barcarena Power Plant” and "PortoCem Power Plant") located in Pará, Brazil;

our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal");

our LNG terminal (“Barcarena Facility”) and power plant located in Pará, Brazil;

our LNG terminal (“Ireland Facility”) and power plant in Ireland, our first green hydrogen project ("ZeroPark I") and Klondike Digital Infrastructure, our newly-launched power and data center infrastructure business ("Klondike").

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Our “Fast LNG,” or “FLNG,” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a lower cost and faster deployment schedule than other greenfield alternatives.

Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

Semi-permanently moored FSUs will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application.

Our initial Fast LNG units were constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas.

The Kiewit facility specializes in the fabrication and integration of liquefaction projects.

In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity.

Our first Fast LNG unit has been deployed offshore to Altamira, Mexico, and we expect to deploy additional units over the next two years.

We describe our currently planned projects below.

In the first quarter of 2023, we executed an agreement with CFE to supply natural gas for one FLNG unit located off the coast of Altamira, Tamaulipas, Mexico.

The 1.4 million ton per annum (“MTPA”) FLNG unit is utilizing CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes.

Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in the process of commissioning the project.

While we experienced delays in commissioning our first FLNG unit, which impacted our results of operations in this period and may impact our results in future periods, in July 2024, we began to produce LNG, and we expect to achieve run-rate production later in 2024.

We sold the first full cargo from this facility on September 30, 2024.

In the first quarter of 2024, we executed an agreement with CFE to supply natural gas to an onshore liquefied natural gas terminal with up to two 1.4 MTPA FLNG units.

The terminal is to be located at the existing Altamira LNG import facility and would source feedgas from the Sur de Texas-Tuxpan Pipeline.

Fast LNG is anchored by key benefits over conventional liquefaction projects.

In particular, we believe installing modular equipment in a shipyard will meaningfully expedite timelines.

In addition, placing solutions offshore provides greater access to natural gas and optimized marine logistics.

We describe our operational and planned FLNG projects below.

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Our first Fast LNG unit has been deployed off the coast of Altamira, Tamaulipas, Mexico, and was placed into service in the fourth quarter of 2024.

The 1.4 million ton per annum (“MTPA”) FLNG unit utilizes CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes.

This first FLNG unit has been fully commissioned, and we are in the process of increasing available liquefaction capacity through optimization projects.

We expect to deploy up to two 1.4MTPA additional FLNG units onshore at the existing Altamira LNG import facility.

The terminal also would source feedgas from the CFE from the Sur de Texas-Tuxpan Pipeline.

The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals.

infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks.

Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks.

In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana.

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We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement.

As part of our long-term strategy, we are evaluating solutions to optimize power generation and delivery to other markets, connected to our power plant through a regional transmission line starting in 2025.

Construction of the terminal and power plant is substantially complete;

however, we will determine timing of final commissioning and commencement under our PPA based on the most optimal use of our LNG supply chain.

As part of our long-term strategy, we are also evaluating solutions to optimize power generation and delivery to other markets, connected to our power plant through a regional transmission line.

Barcarena Facility

The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines.

The Barcarena Facility is capable of processing over one million MMBtu from LNG per day and storing up to 160,000 cubic meters of LNG.

The Barcarena Facility is capable of delivering almost 600,000 MMBtu from LNG per day and storing up to 160,000 cubic meters of LNG.

We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility.

We substantially completed our Barcarena Facility in 2022 and are in process of final commissioning.

The Barcarena Facility will also supply our new 630MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”).

The Barcarena Facility will also supply our new 630MW combined cycle natural gas-fired power plant located in Pará, Brazil (the “Barcarena Power Plant”).

The power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid.

We expect to complete the Barcarena Power Plant and begin delivering power to nine committed offtakers for 25 years beginning in 2025.

We expect to complete the Barcarena Power Plant in 2025.

In March 2024, we closed the acquisition of PortoCem Geração de Energia S.A.

("PortoCem"), a wholly-owned subsidiary of Ceiba Fundo de Investimento em Participações Multiestratégia- Investimento no Exterior ("Ceiba Energy") in exchange for newly issued 4.8% NFE redeemable Series A Convertible Preferred Stock.

("PortoCem"), a wholly-owned subsidiary of Ceiba Fundo de Investimento em Participações Multiestratégia- Investimento no Exterior ("Ceiba Energy").

PortoCem is the owner of a 15-year 1.6GW capacity reserve contract in Brazil.

We have received approval to transfer the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build the PortoCem Power Plant to supply the capacity reserve contract using gas from the Barcarena Facility.

We expect to begin delivering electricity under the acquired capacity reserve contract in July 2026.

Santa Catarina Facility

We have developed a 33-kilometer, 20-inch pipeline that connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A.

(“TBG”) pipeline via an interconnection point in the municipality of Garuva.

The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day.

We are in the process of final commissioning of our Santa Catarina Facility.

We have transferred the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE is building the 1.6 GW simple cycle, natural gas-fired power plant ("PortoCem Power Plant") to supply the capacity reserve contract using gas from the Barcarena Facility.

We expect the PortoCem Power Plant to be completed in 2026.

Ireland Facility

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

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The power plant is required to be operational by October 2026.

In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant.

We challenged this decision, and in September 2024, the High Court of Ireland ruled that the ABP did not have appropriate grounds for the denial of our permit.

The ABP has been directed to reconsider our permit application in accordance with Irish law.

The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations.

In the third quarter of 2023, An Bord Pleanála ("ABP"), Ireland's planning commission, denied our application for the development of an LNG terminal and power plant.

We challenged this decision, and in September 2024, the High Court of Ireland ruled that ABP did not have appropriate grounds for the denial of our p ermit.

In March 2025, APB withdrew their appeal to the September 2024 High Court decision.

ABP is now reconsidering our planning application in accordance with Irish Law.

Further, in March 2025, ABP granted our application to construct a 600 MW power plant and a separate application to construct the 220 kV electricity interconnect.

We are able to fuel this power plant via our LNG marine import terminal, if approved, or using gas provided from our permitted pipeline interconnection.

The continued development of this project is uncertain and there are multiple risks, including regulatory risks, which could preclude the development of this project;

however, management continues to assess all options in respect of future developments for the land held.

In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable.

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Once completed, we expect ZeroPark I to be the largest green hydrogen plant in the United States.

We recently launched Klondike, a power and data center development business dedicated to working with hyperscale customers to build and operate data centers.

In 2024, we launched Klondike, a power and data center development business dedicated to working with hyperscale customers to build and operate data centers.

This venture comes in response to a significant need for turnkey digital infrastructure to support the next stage of explosive growth in artificial intelligence.

Klondike will employ independent power sources that utilize behind-the-meter on-site power.

Klondike will develop independent power sources that utilize and provide behind-the-meter on-site power.

This innovative approach is designed to address all major constraints of digital infrastructure development, providing grid stability, significant transmission capacity, power reliability, energy cost savings, and scalability.

This approach not only reduces the demand for power from the grid but also contributes power back to it.

Klondike is currently developing a geographically diverse portfolio of data center sites to satisfy the requirements of hyperscale users.

Klondike plans to develop a geographically diverse portfolio of data center sites to satisfy the requirements of hyperscale users.

Klondike has more than 1,000 acres of developable land across sites in Brazil, Ireland, and the United States that it either owns or leases.

These locations have large existing power plants or permits in process to build several gigawatts of power, connectivity to fiber networks, access to transmission and water.

These locations have, or will have, large existing power plants or permits in process to build several gigawatts of power, connectivity to fiber networks, access to transmission and water.

Recent Developments

Equity Offering

On October 1, 2024, the Company entered into an Underwriting Agreement with several underwriters to issue and sell 46,349,942 shares of our Class A common stock, par value $0.01 per share, at a purchase price to the public of $8.63 per share, less underwriting discounts and commissions, in a registered public offering (the "Equity Offering").

Our chief executive officer, Wesley R.

Edens, agreed to purchase 5,793,742 shares at the public offering price per share and on the same terms as the other purchasers in the Equity Offering.

The Equity Offering closed on October 2, 2024.

We received net proceeds of approximately $387.3 million after underwriters' discounts and commissions and the estimated offering expenses payable by the Company.

Transaction Support Agreement and Exchange and Subscription Agreement

On September 30, 2024, we entered into a Transaction Support Agreement (the "TSA") with certain holders of our 2025 Notes, 2026 Notes, and 2029 Notes.

The TSA relates to a series of transactions, among the Company, certain of the Company's direct and indirect subsidiaries and certain holders of the 2025 Notes, 2026 Notes and 2029 Notes ( the "Supporting Holders"), intended to extend the maturity profile of our indebtedness while providing additional operating liquidity and financial flexibility.

On November 6, 2024, we entered into a privately negotiated exchange and subscription agreement (the "Exchange and Subscription Agreement") with the Supporting Holders to implement the transactions described in the TSA.

Pursuant to the Exchange and Subscription Agreement, (i) NFE Financing LLC ("NFE Financing"), an indirectly owned subsidiary of the Company, will sell to the Supporting Holders approximately $1.2 billion aggregate principal amount of 12.00% Senior Secured Notes due 2029 (the "New Notes") (the transactions described in clause (i), the "Subscription Transactions") and (ii) NFE Financing will issue to the Supporting Holders $1.5 billion aggregate principal amount of New Notes in a dollar-for-dollar exchange for our 2026 Notes and 2029 Notes (the "Exchange Transactions" and together with the Subscription Transactions, the "Transactions").

The New Notes will be issued pursuant to an indenture (the "New Notes Indenture") and will be issued in private placements in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act.

We intend to use net proceeds from the Transactions to repay in full the outstanding aggregate principal amount of our 2025 Notes and for general corporate purposes.

Pursuant to the Exchange and Subscription Agreement, the Supporting Holders may elect to receive a commitment fee equal to either (i) 5% of the aggregate principal amount of such Supporting Holder’s New Notes, payable in shares of our Class A common stock, at a price of $8.63 per share (the "Commitment Fee Shares"), (ii) 2% of the aggregate principal amount of such Supporting Holder’s New Notes, payable in kind in the form of additional New Notes (the "Commitment Fee Notes"), or (iii) a combination of the foregoing.

To the extent any Supporting Holder elects to receive Commitment Fee Notes, the equivalent value in Commitment Fee Shares will be ratably reallocated amongst the other Supporting Holders to ensure that the Supporting Holders will in any case receive 5% of the total amount of New Notes payable in Commitment Fee Shares.

In the event any Supporting Holder elects to receive the Commitment Fee Shares, such Supporting Holder will enter into a Registration Rights Agreement with the Company, pursuant to which such Supporting Holder is entitled to certain registration rights and subject to certain lock-up restrictions.

Any Supporting Holders may not, subject to customary exceptions, offer, sell, contract to sell, pledge or otherwise dispose of the Commitment Fee Shares for a period of six months from the date of the Registration Rights Agreement without our prior written consent.

New Notes Indenture

Interest on the New Notes will be payable semi-annually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025.

The New Notes will mature on November 15, 2029 and are payable in full on maturity date.

NFE Financing may redeem the New Notes, in whole or in part, at any time prior to maturity, subject to certain prepayment premiums.

NFE Financing is required to prepay the New Notes, subject to repurchase premiums, upon occurrence of change of control events and other specified prepayment events.

Additionally, the New Notes will be subject to a par repurchase offer in connection with any “Pass Through Prepayment Event” (defined as any prepayment made under the Brazil Parent Credit Agreement or the Series II Credit Agreement (each, as defined below)).

The New Notes will be guaranteed on a senior secured basis by NFE Financing’s wholly-owned subsidiary, Bradford County Real Estate Partners LLC ("New Notes Guarantor"), which owns our land in Wyalusing, Pennsylvania.

The New Notes will be secured by first-priority liens on (a) all assets of NFE Financing, including the promissory note evidencing indebtedness under the Series II Credit Agreement, the promissory note evidencing indebtedness under the Brazil Parent Credit Agreement, approximately 45% of the equity in NFE Brazil Holdings Limited ("NFE Brazil Holdings"), which owns our Brazil business, and 100% of the equity in the New Notes Guarantor and (b) all assets of the New Notes Guarantor.

In connection with NFE Financing’s issuance of the New Notes, NFE will:

(i) enter into approximately $1.4 billion Series II Credit Agreement (as defined below) with NFE Financing, (ii) enter into an approximately $970 million Series I Credit Agreement (as defined below) with NFE Brazil Investments LLC (“Brazil Parent”), an indirectly owned, restricted subsidiary of the Company and the direct parent of NFE Financing, and (iii) further cause Brazil Parent to enter into an approximately $970 million Brazil Parent Credit Agreement (as defined below) with NFE Financing.

Intercompany loans

Brazil Parent Credit Agreement

NFE Financing and Brazil Parent will enter into a credit agreement (the “Brazil Parent Credit Agreement”), whereby NFE Financing will provide a term loan of approximately $970 million (the “Brazil Parent Term Loan”) to Brazil Parent, which will mature in November 2029.

The obligations under the Brazil Parent Credit Agreement will be secured by substantially all assets of Brazil Parent (including a pledge of the equity interests held by Brazil Parent in NFE Brazil Holdings).

Brazil Parent may redeem the Brazil Parent Term Loan, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

Brazil Parent is required to prepay the Brazil Parent Term Loan, subject to repurchase premiums, upon occurrence of certain events, including any change of control and receipt of net proceeds from any prepayment under the Series I Credit Agreement (as defined below).

The Brazil Parent Credit Agreement is expected to contain usual and customary representations and warranties, covenants and events of default for financings of this type.

Series I Credit Agreement

NFE and Brazil Parent will enter into a term loan credit agreement (“Series I Credit Agreement”), under which Brazil Parent will provide NFE a senior secured term loan in an aggregate principal amount of approximately $970 million (the “Series I Term Loan”).

We intend to use proceeds to repay in full the outstanding aggregate principal amount of our 2025 Notes and consummate a portion of the Exchange Transactions.

Series II Credit Agreement

NFE and NFE Financing will enter into a term loan credit agreement (“Series II Credit Agreement”), under which NFE Financing will provide NFE a senior secured term loan in an aggregate principal amount of approximately $1.4 billion (the “Series II Term Loan”).

The proceeds will be used to consummate the Exchange Transactions.

Both Series I and Series II Term Loan will mature in November 2029 and will be payable in full on the maturity date.

The obligations under both the Series I Credit Agreement and Series II Credit Agreement will be guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes and the 2029 Notes.

The obligations under the Series I and Series II Credit Agreement will be secured by substantially the same collateral that currently secures the 2026 Notes and 2029 Notes.

An equal priority intercreditor agreement will govern the treatment of the collateral.

We may redeem the Series I and Series II Term Loan, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

In addition, we will be required to prepay the Series I and Series II Term Loan upon the occurrence of any change of control (as defined in the New Notes Indenture and the Brazil Parent Credit Agreement), and with the net proceeds of certain asset sales, condemnations and debt and convertible securities issuances.

Both Series I and Series II Credit Agreement are expected to contain customary representations, warranties, covenants and events of default, subject to certain thresholds and grace periods, typical for financings of this type.

Credit agreement amendments

On November 6, 2024, we entered into the Ninth Amendment to our Revolving Credit Agreement (the “Ninth Amendment”), which extends the maturity date of the Revolving Facility for consenting lenders from April 15, 2026 to October 15, 2027, subject to certain events that would cause the maturity to spring to an earlier date as described in the Ninth Amendment.

On November 6, 2024, we entered into the Fifth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement (the “Fifth Amendment”, and together with the “Ninth Amendment,” the “Amendments”).

The Amendments, among other things, modify the definition of Excluded Assets and exclude certain assets of our Brazil business from the definition of Excluded Assets.

The Amended Credit Agreements also amend the financial covenant that tests the consolidated first lien debt ratio.

The consolidated first lien debt ratio cannot exceed (i) 9.50 to 1.00, for the fiscal quarters ending March 31, 2025 through June 30, 2025, (ii) 8.50 to 1.00, for the fiscal quarters ending September 30, 2025 through December 31, 2025, (iii) 8.00 to 1.00, for the fiscal quarters ending March 31, 2026 through June 30, 2026, and (iv) 7.50 to

1.00, for the fiscal quarters ending September 30, 2026 and each fiscal quarter thereafter.

The Amended Credit Agreements also add a fixed charge coverage ratio test.

Commencing with the fiscal quarter ending March 31, 2025, we cannot permit the fixed charge coverage ratio (the ratio of consolidated EBITDA to fixed charges) for the Company and its restricted subsidiaries to be less than 0.80 to 1.00 for the fiscal quarter ending March 31, 2025 and, for the fiscal quarter ending June 30, 2025 and each fiscal quarter thereafter, 1.00 to 1.00.

Additionally, the Amendments modify how consolidated EBITDA is calculated to more closely align with the calculations in certain of our existing term loan facilities and also remove the Debt to Total Capitalization Ratio.

Lumina Note Purchase Agreement

On November 6, 2024, NFE Brazil Financing Limited (“NFE Brazil”), a wholly-owned, indirect subsidiary of the Company, entered into a note purchase agreement (the “Note Purchase Agreement”) to issue and sell up to $350 million aggregate principal amount of its 15% Senior Secured Notes due 2029 (the “NFE Brazil Notes”) at a purchase price of 97.75% of the principal amount.

The obligations under the NFE Brazil Notes will be guaranteed by the Company and certain subsidiaries of NFE Brazil, and NFE Brazil, its subsidiary guarantors and certain of its other subsidiaries will grant security interests in certain of their assets to secure the NFE Brazil Notes.

On May 12, 205, the Company entered into the following credit agreement amendments:

The Company entered into the Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”) which amends that certain Credit Agreement, dated as of April 15, 2021 (as amended, restated or otherwise modified from time to time, the

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“Existing RCF” and the Existing RCF as amended by the Twelfth Amendment, the “Amended RCF”), by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and as collateral agent.

Among other things, the Twelfth Amendment waives the requirement that the Company pay 75% of net proceeds from certain asset sales to repay indebtedness, allowing the Company to apply $270,000 of proceeds from the sale of the Jamaica Business to the extended tranche of the Existing RCF prior to September 30, 2025, when such amount was due.

The Company plans to use the remaining proceeds to reinvest in the Company’s business and repay indebtedness under the Amended TLA (as defined below).

The Company entered into the Fifth Amendment to Credit Agreement (the “Fifth Amendment”) which amends that certain Credit Agreement, dated as of July 19, 2024 (as amended, restated or otherwise modified from time to time, the “Existing TLA” and the Existing TLA as amended by the Fifth Amendment, the “Amended TLA”).

The Company entered into the Eighth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement (the “Eighth Amendment”) which amends that certain Uncommitted Letter of Credit and Reimbursement Agreement, dated as of July 16, 2021 (as amended, restated or otherwise modified from time to time, the “Existing ULCA” and the Existing ULCA as amended by the Eighth Amendment, the “Amended ULCA”), by and among the Company, the guarantors from time to time party thereto, Natixis, New York Branch, as Administrative Agent, Natixis, New York Branch, as ULCA Collateral Agent, Natixis, New York Branch, and each of the other financial institutions party thereto, as Lenders and Issuing Banks.

The Fifth Amendment, the Eighth Amendment and the Twelfth Amendment are referred to herein collectively as the “Amendments;” the Amended TLA, the Amended ULCA and the Amended RCF are referred to herein collectively as the “Amended Credit Agreements.” The Existing TLA, the Existing ULCA and Existing RCF are referred to herein collectively as the “Existing Credit Agreements.”

The Twelfth Amendment, among other things, (i) provides for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio contained therein for the fiscal quarter ending June 30, 2025, (ii) permits $270,000 of proceeds from the sale of the Jamaica Business to be used to prepay and terminate a portion of loans and commitments currently outstanding and otherwise does not require the proceeds of the sale of the Jamaica Business to be used to prepay loans and commitments and (iii) provides that the asset sale sweep mandatory prepayment will now terminate effectiveness once aggregate commitments are reduced to $550,000 from $600,000.

The Fifth Amendment, among other things, (i) requires $55,000 of proceeds from the sale of the Jamaica Business to be used to prepay a portion of loans currently outstanding and otherwise does not require the proceeds from the sale of the Jamaica Business to be used to prepay loans;

(ii) increases the applicable margin to 6.70% for SOFR loans and 5.70% for Base Rate Loans and implements a SOFR floor of 4.30% and a base rate floor of 5.30%;

(iii) requires the Company to make mandatory prepayments with 12.5% of proceeds of a $659,000 request for equitable adjustment and any other proceeds related to the early termination of our FEMA contracts, if and when such proceeds are received, to pay down a portion of the indebtedness outstanding under loans thereunder and, in the case of certain asset sales, reduce the commitments thereunder.

Additionally, the Fifth Amendment amends certain of the financial covenants.

After giving effect to the Fifth Amendment, the consolidated first lien debt ratio cannot exceed (i) 8.75 to 1.00, for the fiscal quarters ending March 31, 2025, (ii) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (iii) 6.50 to 1.00, for the fiscal quarter ending December 31, 2025, (iv) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 and September 30, 2026 and (v) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter.

The Fifth Amendment added a fixed charge coverage ratio covenant and removed the debt to total capitalization covenant to the Amended TLA.

Commencing with the fiscal quarter ending March 31, 2025, the Company cannot permit the fixed charge coverage ratio for the Company and its restricted subsidiaries to be less than or equal to 0.80 to 1.00 for the fiscal quarter ending March 31, 2025 and, for the fiscal quarter ending September 30, 2025 and each fiscal quarter thereafter, 1.00 to 1.00.

Neither the first lien debt ratio covenant nor the fixed charge coverage ratio covenant will be tested for the fiscal quarter ending June 30, 2025.

After giving effect to the Fifth Amendment, the financial covenants set forth above are consistent with the corresponding financial covenants in the Amended RCF and Amended LCF.

The Eighth Amendment, among other things, provides for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio contained therein for the fiscal quarter ending June 30, 2025.

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Further to the above, the Amendments each added a covenant limiting the amount of cash the Company can use to repurchase outstanding senior secured notes due 2026, other than payments to avoid springing maturities in respect thereof or with proceeds of certain permitted debt or equity refinancing transactions.

Sale of Jamaica Business

On May 14, 2025, the Company completed the sale of the Jamaica Business to Excelerate Energy Limited Partnership (“EELP”), a subsidiary of Excelerate Energy, Inc., for $1.055 billion in cash, subject to certain purchase price adjustments.

In conjunction with closing, the Company repurchased all outstanding South Power Bonds for $227,157, including a 1.0% prepayment penalty and accrued interest.

After the repayment of debt, the Company received net proceeds of approximately $678,480, with an additional $98,635 proceeds held in escrow and to be returned to the Company on the release dates as stated in the EAPA.

As a result of the Amended Agreements, the Company repaid and permanently reduced the Revolving Facility commitments of $270,000 and repaid $55,000 of the Term Loan A Credit Agreement with the sale proceeds.

Other Matters

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On September 26, 2024, the United States Coast Guard ("USCG") filed a Letter of Recommendation with FERC in which it assessed our Letter of Intent dated April 12, 2024, and our Waterway Suitability Assessment, dated August 26, 2024, in respect of future ship to ship transfers with alternative vessels, and recommended against the allowance of the proposed operations.

Further, the USCG issued a Letter of Warning in respect of our ongoing ship to ship transfers of LNG operations within the San Juan port limits.

On October 21, 2024, we filed an appeal with the USCG under 33 CFR 160.7 and are awaiting a response.

On October 25, 2024, FERC issued a notice of intent to prepare an Environmental Impact Statement, which included, among other things, two public scoping sessions in Puerto Rico scheduled for November 18, 2024 in accordance with the National Environmental Policy Act.

Results of Operations – Three Months Ended September 30, 2024 compared to Three Months Ended June 30, 2024 and Nine Months Ended September 30, 2024 compared to Nine Months Ended September 30, 2023

Further, on September 26, 2024, the USCG issued a Letter of Warning in respect of our ongoing ship to ship transfers of LNG operations within the San Juan port limits.

On October 21, 2024, we filed an appeal with the USCG under 33 CFR 160.7.

In December 2024 and February 2025, we submitted an updated Letter of Intent and Waterway Suitability Assessments detailing our alternative operational plans to the USCG and are working collaboratively with the USCG to obtain a new Letter of Recommendation to FERC in support of our operations, which we expect to be imminently forthcoming.

In concert with our collaboration with the USCG regarding our new operational plans, we withdrew our appeal on February 14, 2025.

On October 25, 2024, FERC issued a notice of intent to prepare an Environmental Impact Statement, which included, among other things, two public scoping sessions in Puerto Rico held on November 18, 2024 in accordance with the National Environmental Policy Act.

Results of Operations – Three Months Ended March 31, 2025 compared to Three Months Ended December 31, 2024 and Three Months Ended March 31, 2024

Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin.

Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure.

Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a

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non-GAAP measure.

We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization.

Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus

Vessel operating expenses, each as reported in our financial statements.

Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements.

We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets.

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Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business.

The tables below present our segment information for the three months ended September 30, 2024 and June 30, 2024, and for the nine months ended September 30, 2024 and September 30, 2023:

Three Months Ended September 30, 2024

The tables below present our segment information for the three months ended March 31, 2025, December 31, 2024 and March 31, 2024:

Three Months Ended March 31, 2025

(in thousands of $) Terminals and

Infrastructure Ships Total Segment Consolidation

and Other (3)

and Other Consolidated

Total revenues $ 431,927 $ 38,609 $ 470,536 $ — $ 470,536

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54,957 — 54,957 — 54,957

Deferred earnings from contracted sales (5)

60,000 — 60,000 (60,000) —

Segment Operating Margin $ 74,593 $ 31,433 $ 106,026 $ — $ 106,026

Three Months Ended September 30, 2024

Three Months Ended March 31, 2025

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 106,026

Three Months Ended June 30, 2024

Three Months Ended December 31, 2024

(in thousands of $) Terminals and

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34,411 — 34,411 — 34,411

Deferred earnings from contracted sales (5)

90,000 $ — 90,000 (90,000) —

Segment Operating Margin $ 206,099 $ 34,144 $ 240,243 $ 107,727 $ 347,970

Three Months Ended June 30, 2024

(in thousands of $) Consolidated

Gross margin (GAAP) $ 120,938

Depreciation and amortization 37,413

Consolidated Segment Operating Margin (Non-GAAP) $ 158,351

Nine Months Ended September 30, 2024

(in thousands of $) Terminals and

Infrastructure Ships Total Segment Consolidation

and Other (3)

Total revenues $ 1,515,365 $ 128,224 $ 1,643,589 $ 42,273 $ 1,685,862

Cost of sales 776,269 — 776,269 — 776,269

Vessel operating expenses — 25,153 25,153 — 25,153

Operations and maintenance 139,902 — 139,902 — 139,902

Deferred earnings from contracted sales(5) 150,000 — 150,000 (150,000) —

Segment Operating Margin $ 749,194 $ 103,071 $ 852,265 $ (107,727) $ 744,538

Nine Months Ended September 30, 2024

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Three Months Ended December 31, 2024

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 347,970

Nine Months Ended September 30, 2023

Three Months Ended March 31, 2024

(in thousands of $) Terminals and

Infrastructure Ships Total Segment Consolidation

and Other (3)

and Other Consolidated

Total revenues $ 647,737 $ 42,584 $ 690,321 $ — $ 690,321

Cost of sales (1)

229,117 — 229,117 — 229,117

Vessel operating expenses (3)

— 8,396 8,396 — 8,396

Operations and maintenance (3)

68,548 — 68,548 — 68,548

Segment Operating Margin $ 350,072 $ 34,188 $ 384,260 $ — $ 384,260

Nine Months Ended September 30, 2023

Three Months Ended March 31, 2024

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 384,260

(1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are economic hedges of our commodity purchases and sales, and realized losses of $0.3 million and realized gains of $141.6 million for the three and nine months ended September 30, 2023, respectively, were recognized as a reduction to Cost of sales in the segment measure.

No such transactions were completed in 2024.

We recognized unrealized gains of $0.4 million and unrealized losses of $107.9 million on the mark-to-market value of derivative transactions for the three and nine months ended September 30, 2023, respectively, and these gains and losses reconcile Cost of sales in the segment measure to Cost of sales in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) .

We have excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure.

Contract acquisition costs of $6.2 million for the nine months ended September 30, 2023 are shown as a reduction to Cost of sales in the segment measure.

There were no contract acquisition costs incurred in 2024.

(2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

(3) Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $150.0 million;

a portion of these deferred earnings of $42.3 million were recognized upon delivery during the third quarter of 2024.

In 2023, the effective share of revenues, expenses and operating margin attributable to our ownership of the common units of Hilli LLC in the segment measure, prior to the disposition to this investment, as well as unrealized mark-to-market gain or loss on derivative instruments, are also removed.

(1) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive (Loss) Income .

(2) For the three months ended December 31, 2024, Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $107.7 million which were recognized during the fourth quarter of 2024.

(3) Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP.

(5) Deferred earnings from contracted sales represent forward sales transactions that were contracted in the current period and prepayment for these sales was received.

Revenue will be recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) when delivery under these forward sales transactions is completed from the fourth quarter of 2024 through 2025.

Terminals and Infrastructure Segment

Three Months Ended

(in thousands of $) September 30, 2024 June 30, 2024 Change

Total revenues $ 482,200 $ 385,428 $ 96,772

Cost of sales (exclusive of depreciation and amortization) 325,292 221,860 103,432

Operations and maintenance 32,062 39,292 (7,230)

Deferred earnings from contracted sales 60,000 90,000 (30,000)

Segment Operating Margin $ 184,846 $ 214,276 $ (29,430)

Nine Months Ended,

(in thousands of $) September 30, 2024 September 30, 2023 Change

(in thousands of $) March 31, 2025 December 31, 2024 Change March 31, 2024 Change

Total revenues $ 431,927 $ 528,908 $ (96,981) $ 647,737 $ (215,810)

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Operations and maintenance 54,957 34,411 20,546 68,548 (13,591)

Deferred earnings from contracted sales 150,000 — 150,000

Segment Operating Margin $ 74,593 $ 206,099 $ (131,506) $ 350,072 $ (275,479)

Total revenue

Total revenue for the Terminals and Infrastructure Segment increased by $96.8 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024.

The increase was primarily driven by higher cargo sales and Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment, partially offset by lower incentive fee revenue from the Genera's operation and maintenance contract.

The increase in revenue in the third quarter of 2024 when compared to the second quarter of 2024 was primarily attributable to the following:

• Revenue from cargo sales was $174.6 million for the three months ended September 30, 2024, increasing from $24.5 million for the three months ended June 30, 2024.

• Volumes delivered to downstream terminal customers were substantially consistent, increasing from 20.2 TBtu in the second quarter of 2024 to 20.7 TBtu in the third quarter of 2024.

• The average Henry Hub index pricing used to invoice our downstream customers increased by 14% for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024.

Total revenue for the Terminals and Infrastructure Segment increased by $69.3 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023, and the increase in revenue was primarily attributable to the following:

• For the nine months ended September 30, 2024, volumes delivered to downstream customers were 62.8 TBtu as compared to 46.1 TBtu for the nine months ended September 30, 2023.

• In 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets in the second and third quarters of 2023, and the increase in volumes for the nine months ended September 30, 2024 is primarily attributable to additional sales in Puerto.

Our customer terminated the grid stabilization project in the first quarter of 2024, but we continue to sell volumes into these power plants under a new island-wide gas sale agreement signed with PREPA.

Although we delivered significantly higher volumes in the current year, our revenue was impacted by lower Henry Hub pricing and lower cargo sale revenue.

• The average Henry Hub index pricing used to invoice our downstream customers decreased by 22% for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023.

• The Company had $199.1 million in cargo sales for the nine months ended September 30, 2024.

Revenue from cargos sales was $617.1 million for the nine months ended September 30, 2023.

Total revenue for the Terminals and Infrastructure Segment decreased by $97.0 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024, and total revenue for the Terminals and Infrastructure Segment decreased by $215.8 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

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The decrease in revenue in the first quarter of 2025 when compared to the fourth quarter of 2024 was primarily attributable to contract novation income recognized during the three months ended December 31, 2024, and a decrease in volumes delivered to downstream customers.

• The Company novated an LNG supply contract to a customer, recognizing $235.6 million within segment revenue in the fourth quarter of 2024.

No such contract novation income was recognized during the three months ended March 31, 2025.

• Volumes delivered to downstream terminal customers decreased from 18.4 TBtu in the fourth quarter of 2024 to 13.8 TBtu in the first quarter of 2025 due to maintenance at our Old Harbour and San Juan facilities.

• We recognized $182.7 million of revenue from cargos sales for the three months ended March 31, 2025 as compared to $91.9 million for the three months ended December 31, 2024.

• The average Henry Hub index pricing used to invoice our downstream customers increased by 31% for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

The decrease in revenue in the first quarter of 2025 when compared to the first quarter of 2024 was primarily attributable to the termination of our grid stabilization project in the first quarter of 2024.

The decrease in revenue was partially offset by higher Henry Hub index pricing and cargo sales.

• For the three months ended March 31, 2025, volumes delivered to downstream customers were 13.8 TBtu as compared to 22.0 TBtu for the three months ended March 31, 2024 due to maintenance at our Old Harbour and San Juan facilities.

• The higher volumes in the first quarter of 2024 was primarily attributable to additional sales in Puerto Rico from our grid stabilization project.

Our customer terminated the grid stabilization project in the first quarter of 2024, but we continue to sell volumes into these power plants under an island-wide gas sale agreement signed with PREPA.

The agreement is set to expire in June 2025, and we are in active discussions with PREPA for an extension.

• Revenue from cargos sales was $182.7 million for the three months ended March 31, 2025.

The Company had no cargo sales for the three months ended March 31, 2024 as we were able to utilize all volumes under our supply contracts in our downstream terminal operations.

• The average Henry Hub index pricing used to invoice our downstream customers increased by 63% for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

Cost of sales

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

Historically, our LNG and natural gas supply has been purchased from third parties or converted in our Miami Facility.

Following the anticipated sale of our Miami Facility, we expect to continue sourcing LNG from third parties and for a portion of our supply to be generated by our first FLNG unit.

We source LNG and natural gas from third parties and our own liquefaction facilities, including our first Fast LNG unit which was placed into service in the fourth quarter of 2024.

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

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Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue.

Cost of sales increased by $103.4 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024, which was attributable to higher cost of gas purchased and cargo sales.

Our cost to deliver natural gas volumes increased to $6.65 per MMBtu for the three months ended September 30, 2024 from $6.42 per MMBtu for the three months ended June 30, 2024.

After our FLNG asset is fully commissioned and operational, we expect to be able to produce LNG at a lower cost than the LNG purchased under our supply contracts.

We incurred increased cost of LNG for LNG cargo sales during the third quarter of 2024 by $76.7 million compared to the second quarter of 2024 due to higher volumes delivered.

Cost of sales increased by $287.8 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023, which was attributable to the following activity:

• We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $76.4 million during the nine months ended September 30, 2024 due to increased volumes delivered.

We delivered 36% more volume to our downstream terminal customers in the current period.

While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was lower,

decreasing to $ 6.65 per MMBtu for the nine months ended September 30, 2024 from $ 7.26 per MMBtu for the nine months ended September 30, 2023.

• Vessel costs increased by $59.8 million, for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023.

The increase is primarily driven by additional vessels being used for servicing our terminals during 2024.

• We recognized payroll and other operating costs of $77.0 million to provide services under Genera's operations and maintenance contract for the nine months ended September 30, 2024 compared to $16.3 million for the nine months ended September 30, 2023;

these costs are passed onto PREPA.

Only one quarter of such costs were incurred during the nine months ended September 30, 2023 as our contract commenced on July 1, 2023.

• We incurred decreased cost of LNG for LNG cargo sales during the nine months ended September 30, 2024 by $72.7 million as our LNG cargo sale activity has been significantly lower in the first three quarters of 2024.

• In the nine months ended September 30, 2023, realized gains of $141.9 million from the settlement of commodity swap transactions, entered into as an economic hedge to reduce the market risks associated with commodity prices, were included as reduction of cost of sales in the segment measure.

For segment performance measures, unrealized mark to market gains and losses are excluded until settled.

No such transactions occurred in the current period.

The weighted-average cost of our LNG inventory balance to be used in our operations as of September 30, 2024 and December 31, 2023 was $7.46 per MMBtu and $7.33 per MMBtu, respectively.

Cost of sales increased by $14.0 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

• In the first quarter of 2025, we incurred $103.8 million of cargo sales costs as compared to $53.9 million for the three months ended December 31, 2024.

• We delivered 25% lower volumes to our customers in the first quarter of 2025, decreasing the cost of LNG to supply our downstream customers by $27.7 million.

The weighted average cost of gas purchased increased from $8.75 per MMBtu for the three months ended December 31, 2024 to $9.57 per MMBtu for the three months ended March 31, 2025.

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Cost of sales increased by $73.3 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024, which was attributable to the following:

• In the first quarter of 2025, we incurred $103.8 million of cargo sales costs.

In the first quarter of 2024, we did not have any cargo sales and we delivered higher volumes to our downstream terminal customers.

• We delivered 37% lower volumes to our customers during the first quarter of 2025.

Though we delivered lower volumes to our downstream customers, the cost of gas purchased increased significantly from $6.96 per MMBtu in the first quarter of 2024 to $9.57 per MMBtu in the first quarter of 2025.

In addition, the Henry Hub pricing also increased by 63% from March 2024 to March 2025.

• Vessel costs increased by $12.3 million, for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024, principally due to lower vessel utilization in the first quarter of 2025.

The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2025 and December 31, 2024 was $8.73 per MMBtu and $6.90 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 decreased by $7.2 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024.

The decrease was primarily due to lower maintenance costs at our terminals during the third quarter and termination of the lease of three turbines during the second quarter of 2024.

Operations and maintenance increased $18.7 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023 .

We incurred additional operations and maintenance costs at our La Paz Power Plant during nine months ended September 30, 2024 as it was placed into service in September 2023.

Additional operations and maintenance cost were also incurred at our La Paz Facility in 2024 to meet higher customer demand.

Deferred earnings from contracted sales

In the second and third quarters of 2024, we completed forward sales receiving prepayments from the buyer of $90.0 million and $60.0 million respectively.

The prepayment was based on the fair market value of these sales as compared to our supply cost, and our CODM includes these results in his evaluation of Terminals and Infrastructure operations.

Revenue for these sales will be recognized in our Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) as deliveries under this contract will occur in the fourth quarter of 2024 through 2025.

A portion of these deferred earnings of $42.3 million were recognized upon delivery during the third quarter of 2024.

Both the forward contracted sale and our supply contract are based on Henry Hub which mitigates the impact that changes in commodity pricing will have on our results of operations.

Operations and maintenance increased by $20.5 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

We placed our first Fast LNG project and Santa Catarina Facility into service in the fourth quarter of 2024.

The increase was primarily attributable to payroll, maintenance, logistics and other costs incurred for operating these new facilities placed into service in 2024.

Operations and maintenance decreased by $13.6 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024 .

In the first quarter of 2024, our grid stabilization contract was terminated and assets related to the project were sold to PREPA.

The decrease in costs during the three months ended March 31, 2025 are primarily due to lease and other maintenance costs that were no longer incurred for the sold assets, partially offset by the increased costs incurred for new facilities placed into service in 2024.

Ships Segment

Three Months Ended,

(in thousands of $) September 30, 2024 June 30, 2024 Change

Total revenues $ 43,062 $ 42,578 $ 484

Vessel operating expenses 8,254 8,503 (249)

Segment Operating Margin $ 34,808 $ 34,075 $ 733

Nine Months Ended,

(in thousands of $) September 30, 2024 September 30, 2023 Change

(in thousands of $) March 31, 2025 December 31, 2024 Change March 31, 2024 Change

Total revenues $ 38,609 $ 42,363 $ (3,754) $ 42,584 $ (3,975)

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

As of September 30, 2024 , three FSRUs and one LNG carrier were leased to customers under long-term arrangements.

On March 15, 2023, we completed disposition of our investment in the common units of Hilli LLC, and after this point, the revenue, expenses and operating margin attributable to our 50% ownership of the Hilli are no longer included in our segment results.

In the first quarter of 2024, we sold the vessel Mazo , for a total consideration of $22.4 million resulting in a gain of $0.4 million.

The gain on sale is included in Loss on sale of assets, net , in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

As of March 31, 2025 , three vessels included in the Energos Formation Transaction were leased to customers under long-term arrangements and are included in this segment.

Total revenue

Total revenue for the Ships segment increased by $0.5 million during the three months ended September 30, 2024 compared to the three months ended June 30, 2024 .

Total revenue for the Ships segment decreased $3.8 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

Total revenue for the Ships segment decreased $4.0 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of certain vessels included in the transaction, and as such, we continue to recognize revenue from the charter of these vessels to third parties.

Total revenue for the Ships segment decreased $102.1 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023.

After the disposition of our investment in the common units of Hilli LLC at the end of the first quarter of 2023, we no longer recognize revenue from the Hilli , decreasing revenue in the Ships segment.

Additionally the charters for four vessels concluded in 2023, lowering vessel revenue for the nine months ended September 30, 2024.

We are now utilizing these vessels in our operations.

The third-party charter of the vessel Energos Maria ended during the fourth quarter of 2024, and we are using the vessel at our terminal operations, resulting in a decrease in the vessel charter revenue.

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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, management fees and costs to operate the Hilli prior to the Hilli Exchange discussed above.

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 is off hire.

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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 remained consistent during the three months ended September 30, 2024 as compared to the three months ended June 30, 2024.

There were no changes to the vessels that comprise the Ships segment in the third quarter of 2024.

Vessel operating expenses decreased $17.1 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023 .

The decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the disposition our investment in the common units of Hilli LLC at the end of the first quarter of 2023.

During 2024, we started using four vessels that were in the Ships segment in 2023 in our terminal operations, resulting in lower vessel operating costs.

Vessel operating expenses decreased $ 1.0 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

Vessel operating expenses decreased $1.2 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

As discussed above, the vessel operating costs were lower as the vessel Maria has been utilized for our terminal operations.

Other operating results

Three Months Ended, Nine Months Ended,

(in thousands of $) September 30, 2024 June 30, 2024 Change September 30, 2024 September 30, 2023 Change

Three Months Ended,

(in thousands of $) March 31, 2025 December 31, 2024 Change March 31, 2024 Change

Selling, general and administrative $ 59,271 $ 61,800 $ (2,529) $ 70,754 $ (11,483)

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Interest expense 213,694 99,527 114,167 77,344 136,350

Other (income) expense, net (5,836) 47,354 (53,190) 60,630 16,150 44,480

Loss on extinguishment of debt — — — 9,754 — 9,754

Income before income from equity method investments and income taxes 14,266 (83,425) 97,691 9,135 390,742 (381,607)

Income (loss) from equity method investments — — — — 12,738 (12,738)

Tax (benefit) provision 2,953 3,435 (482) 28,012 69,476 (41,464)

Other expense (income), net (63,937) 52,447 (116,384) 19,112 (83,049)

Loss on extinguishment of debt, net 467 260,309 (259,842) 9,754 (9,287)

(Loss) income before income taxes (168,703) (182,013) 13,310 78,294 (246,997)

Tax provision (benefit) 28,670 41,497 (12,827) 21,624 7,046

Net income $ (197,373) $ (223,510) $ 26,137 $ 56,670 $ (254,043)

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

Selling, general and administrative increased $11.8 million for the three months ended September 30, 2024, compared to the three months ended June 30, 2024.

The Company incurred payroll severance cost of $7.9 million and additional share-based compensation expense of $2.5 million during the three months ended September 30, 2024.

Selling, general and administrative increased $66.7 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023.

The increase was primarily due to increased share-based compensation expense.

We recognized $47.7 million of share-based compensation expense for RSUs and other equity awards during the first three quarters of 2024;

no significant cost was recognized in the first three quarters of 2023.

In addition, the allowance for bad debt increased by $11.6 million due to an additional allowance recorded during the three months ended March 31, 2024.

Selling, general and administrative decreased by $2.5 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024.

The decrease was mostly driven by the reversal of previously recorded share-based compensation expense due to forfeitures during the quarter ended March 31, 2025.

Selling, general and administrative decreased by $11.5 million for three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

During the quarter ended March 31, 2024, the Company recognized an additional allowance for uncollectible receivables of $11.6 million.

The allowance reduces outstanding receivables for certain customers to reflect the amount that the Company expects to receive.

No significant allowance was recognized during the three months ended March 31, 2025 .

We recognized $5.2 million of share-based compensation costs associated with RSUs issued for the three months ended March 31, 2024.

Due to forfeitures during the quarter ended March 31, 2025 , the Company recognized a reversal of previously recorded share-based compensation expense which significantly lowered the expense for the period.

The decreases above were partially offset by higher screening costs incurred for our development projects during the first quarter of 2025.

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Transaction and integration costs

We did not incur significant transaction and integration costs for the three or nine months ended September 30, 2024.

The transaction and integration costs of $11.9 million and $6.0 million during the three months ended March 31, 2025 and December 31, 2024, respectively, primarily relate to legal fees and other third party costs incurred by the Company in connection with amendments to credit agreements.

During the first quarter of 2025, we paid the Barcarena Debentures and amended the Term Loan B Credit Agreement, and $6.1 million of third party costs associated with these modifications were recognized as Transaction and integration costs.

During the first quarter of 2025, we also incurred $3.9 million of legal fees related to the sale of our Jamaica Business.

Depreciation and amortization

Depreciation and amortization decreased $2.0 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024.

Depreciation and amortization decreased $1.9 million for the nine months ended

September 30, 2024 as compared to the nine months ended September 30, 2023.

The Company classified the Miami Facility as held for sale on June 30, 2024, and no depreciation was recorded after that date.

Depreciation and amortization increased by $14.3 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

The increase is mainly due to depreciation expense on the Fast LNG project and the Santa Catarina Facility that were placed into service during the fourth quarter of 2024.

Depreciation and amortization expense increased by $2.6 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024.

The increase in depreciation expense resulting from the Fast LNG project and the Santa Catarina Facility being placed into service in December 2024, was partially offset by a reduction due to the sale of certain turbines and equipment to PREPA in March 2024.

Asset impairment expense

The Company recognized an impairment of $ 5.3 million that was predominately due to the classification of the Miami Facility as held for sale in the second quarter of 2024.

There was no significant impairment of assets during the three months ended September 30, 2024.

For the three months ended March 31, 2025 and December 31, 2024, the Company recognized an impairment of $0.2 million and $10.7 million related to the sale of the Miami Facility .

There was no impairment of assets during the three months ended March 31, 2024.

Loss on sale of assets, net

The Company had no significant asset sales during the first quarter of 2025 and fourth quarter of 2024.

During the three months ended March 31, 2024, the Company recognized a loss of $77.5 million from the sale of turbines and related equipment to the PREPA.

We did not have any losses on sales during the three months ended September 30, 2024.

Interest expense

Interest expense decreased by $9.3 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024, primarily due to increased capitalization of interest costs.

Interest expense increased by $28.0 million for the nine months ended September 30, 2024 , as compared to the nine months ended September 30, 2023 .

The increase was primarily due to an increase in total principal outstanding due to additional borrowings and amortization of related debt issuance costs.

The total principal balance on outstanding facilities was $8.2 billion as of September 30, 2024 as compared to total principal outstanding of $6.2 billion as of September 30, 2023.

We capitalize a significant portion of our borrowing costs for development projects, and while the principal balances increased, the interest expense did not increase as significantly.

Other (income) expense, net

Other (income) expense, net was $(5.8) million and $47.4 million three months ended September 30, 2024, and June 30, 2024, respectively.

Other (income) expense, net was $60.6 million and $16.2 million for the nine months ended September 30, 2024 and September 30, 2023, respectively.

Other income recognized in the three months ended September 30, 2024 was primarily comprised of foreign currency gains due to remeasurement of USD denominated debt in our Brazil subsidiary.

The gains were partly offset by realized loss on settlement of foreign currency derivative contracts.

Other expense recognized in the nine months ended September 30, 2024 was primarily comprised of foreign currency remeasurement losses and loss on termination of leases of turbines used in the grid stabilization project in Puerto Rico partially offset by interest income.

Interest expense increased by $114.2 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024.

The increase was primarily due to lower interest capitalized of $74.1 million during the quarter ended March 31, 2025 compared to $139.5 million during the quarter ended December 31, 2024.

We placed the Fast LNG project and Santa Catarina Facility into service during the quarter ended December 31, 2024, and are no longer capitalizing interest towards these projects.

In addition, we have incurred increased borrowing costs under the New 2029 Notes (as defined in our Annual Report) and the Brazil Financing Notes.

We also amended our Term Loan A Credit Agreement and recognized an interest expense of $18.1 million relating to origination, structuring and other fees, which were previously capitalized.

Interest expense increased by $136.4 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024.

The increase was primarily due to an increase in total principal outstanding due to additional principal balance outstanding.

The total principal balance on outstanding facilities was $9.4 billion as of March 31, 2025 as compared to total outstanding debt of $7.2 billion as of March 31, 2024.

We also capitalized lower interest expense of $74.1 million during the first quarter of 2025 compared to $104.2 million during the first quarter of 2024 as the Fast LNG project and Santa Catarina Facility were placed into service towards the end of 2024.

In addition, we recognized an interest expense of $18.1 million upon amendment of our Term Loan A credit agreement.

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Other expense (income), net

Other (income) expense, net was $(63.9) million, $52.4 million and $19.1 million for the three months ended March 31, 2025, December 31, 2024 and March 31, 2024, respectively.

The Other income recognized in the three months ended March 31, 2025 was primarily due to foreign currency remeasurement gains in the first quarter of 2025, supported by the appreciation of the Brazilian real against the U.S.

Other expense, net recognized in the three months ended December 31, 2024 and March 31, 2024 was primarily comprised of foreign currency loss due to remeasurement of U.S.

dollar denominated debt in our Brazil subsidiary.

The losses were partly offset by interest income, and realized and unrealized gains on foreign currency derivative contracts.

Loss on extinguishment of debt

During the three months ended March 31, 2025, we recognized $0.5 million of loss on extinguishment of debt related to the repayment of the Barcarena Debentures.

During the fourth quarter of 2024, we repaid all of the 2025 Notes and a portion of the 2026 Notes and 2029 Notes, and recognized as a loss on extinguishment of debt totaling $235.4 million.

During the three months ended March 31, 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes.

We also recognized a premium over the repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes.

We did not have any extinguishment transactions in the third quarter of 2024 or the first three quarters of 2023.

Income (loss) from equity method investments

During 2023, we recognized income of $6.3 million from our equity method investment in Energos and $6.0 million of income from our investment in the common units of Hilli LLC for the period prior to the completion of the disposition of

this investment.

In the first quarter of 2024, we sold substantially all of our stake in Energos resulting in no income or loss from equity method investments for the three or nine months ended September 30, 2024.

Tax provision

We recognized a tax provision for the three months ended September 30, 2024 of $3.0 million compared to a tax provision of $3.4 million for the three months ended June 30, 2024.

We recognized a tax provision of $28.0 million for the nine months ended September 30, 2024 compared to $69.5 million for the nine months ended September 30, 2023.

The decrease in the tax provision for the three and nine months ended September 30, 2024 is mainly due to pre-tax losses in the US and decrease in pre-tax income in foreign jurisdictions which resulted in correlative changes in tax expense in those jurisdictions.

We recognized a tax provision for the three months ended March 31, 2025 of $28.7 million compared to a tax provision of $41.5 million for the three months ended December 31, 2024 and a tax provision of $21.6 million for the three months ended March 31, 2024.

The tax provision recognized in the first quarter of 2025 was primarily driven by the expected gain from sale of the Jamaica Business, inclusion of foreign earnings related to our Brazil operations included in the effective tax rate, and increase in valuation allowance in the U.S.

Factors Impacting Comparability of Our Financial Results

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:

• Our historical financial results do not reflect our Fast LNG solution which we expect will lower the cost of our LNG supply.

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 nine months ended September 30, 2024.

We anticipate that the deployment of Fast LNG liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers.

Though the commissioning of these facilities, particularly our first Fast LNG unit, was delayed from the initially anticipated date, which impacted our results of operations in this period and may impact our results in future periods, we began to produce LNG from our first Fast LNG unit in July 2024.

The first full cargo was loaded onto the Energos Princess vessel and set sail for Europe on September 30, 2024.

We plan to leverage the development process for the first unit in deploying future Fast LNG liquefaction facilities.

• Our historical results of operations include our Jamaica Business.

In May 2025, we completed the sale of our Jamaica Business, and after this point, we will no longer include the results of operations of our Montego Bay Facility and Old Harbour Facility in our financial statements.

• Our future results of operations will include the cost of operating our Fast LNG solution that were not included in our historical financial statements.

We placed our first Fast LNG project into service in the fourth quarter of 2024.

This project represents our largest ever capital project and placing the asset into service from an accounting perspective will significantly increase the depreciation recognized in future periods;

such depreciation will also impact the cost of LNG delivered from the FLNG facility.

We also expect interest expense to increase as we are no longer able to capitalize borrowing costs associated with this development.

While the asset is in service from an accounting perspective, we will continue to optimize the asset to enhance liquefaction capacity.

Such costs that enhance the asset will be capitalized on our Condensed Consolidated Balance Sheets.

• 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, 2024 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant and certain industrial end-users.

We have completed construction of our Barcarena Facility and Santa Catarina Facility and are in the final stages of commissioning these assets.

We are also continuing to develop our Barcarena Power Plant, PortoCem Power Plant, Puerto Sandino Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects.

Additionally, we began to deliver power to the Puerto Rican grid as part of the grid stabilization project in the second quarter of 2023.

In the first quarter of 2024, our contract was terminated and assets related to the grid stabilization project were sold to PREPA.

Our results of operations for the three months ended March 31, 2025 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant and certain industrial end-users.

We placed the Santa Catarina Facility into service in the fourth quarter of 2024.

We have also completed construction of our Barcarena Facility and are in the final stages of commissioning this facility.

We are also continuing to develop our

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Barcarena Power Plant, PortoCem Power Plant, Puerto Sandino Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects.

In the first quarter of 2024, our grid stabilization contract was terminated and related assets were sold to PREPA.

Under our new island-wide gas sale agreement with PREPA, we continue to supply gas to these power generation assets.

• Our historical financial results include the results from our investments in the common units of Hilli LLC and Energos.

On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of our investment in the common units of Hilli LLC (“Hilli Common Units”), disponent owner and operator of the Hilli Episeyo (the “ Hilli ”) through its subsidiary Golar Hilli Corporation, in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange").

As a result of this transaction, we no longer have any ownership interest in the Hilli , and their results are no longer included in NFE's results of operations.

In February 2024, the Company completed the sale of substantially all of its stake in Energos for a total consideration of $136.4 million and retaining an investment in Energos valued at $1.0 million .

As a result of this transaction, we no longer include the results of Energos in our results of operations.

In March 2025, the agreement was amended to extend the term by 100 days to June 2025.

Liquidity and Capital Resources

On September 30, 2024, we entered into a Transaction Support Agreement with certain holders of our 2025 Notes, 2026 Notes and 2029 Notes, setting forth the terms of a series of transactions intended to extend the maturity profile of our indebtedness, while providing additional operating liquidity and financial flexibility.

On November 6, 2024, we entered

into the Exchange and Subscription Agreement with these Supporting Holders, which sets forth the definitive terms of the Transactions, the consummation of which remains subject to customary closing conditions.

We intend to use the proceeds of the Transactions to:

(a) redeem in full the 2025 Notes;

(b) exchange and cancel approximately $1.4 billion aggregate principal amount of 2026 Notes and 2029 Notes on a dollar-for-dollar basis for additional New Notes and (c) pay fees and expenses related to the Transactions and (d) add approximately $300 million in cash to our balance sheet.

See “Recent Developments” for additional detail regarding the Transactions.

The $875.0 million aggregate outstanding principal amount of our 2025 Notes matures on September 15, 2025.

If any of the 2025 Notes remain outstanding 60 days prior to this maturity date (the "Springing Maturity Date"), the outstanding principal under the Revolving Facility, Term Loan B and Term Loan A (defined below) will become immediately due.

In the absence of closing the Transactions, our current liquidity and forecasted cash flows from operations are not sufficient to support the repayment of the 2025 Notes, in full, prior to the Springing Maturity Date, and as such, management concluded that substantial doubt exists related to our ability to continue as a going concern.

Management expects all conditions precedent to be achieved and the Transactions to close in the coming weeks, which will alleviate the substantial doubt.

However, there can be no assurance that we will be successful in closing the Transactions.

We intend to use a portion of the proceeds from the New Notes to redeem all of the outstanding 2025 Notes.

We have issued a notice of redemption conditioned on the closing of the Transactions;

we expect to effectuate the redemption, and satisfy and discharge the indenture governing the 2025 Notes, shortly following the closing of the Transactions.

In addition to cash received from the recent Equity Offering and the Transactions, we expect our current working capital position to improve based on the following:

(1) expected cash flows generated from new gas sale agreements and volume growth in Puerto Rico, Mexico and Brazil (2) sales of our own LNG generated by our first deployed Fast LNG unit;

(3) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil and we have commitments to fund substantially all of the remaining cost of our onshore FLNG project at Altamira;

(4) we have agreed to issue the New Brazil Notes to provide additional financing to construct our PortoCem Power Plant;

(5) our relationships with certain significant vendors, including vendors constructing our Fast LNG assets, have allowed us to extend our payment terms to better align with the expected completion of our first Fast LNG project;

and (6) the anticipated sale of our Miami Facility in the fourth quarter of 2024.

In addition, we have begun to identify strategic partners for one or more of our primary businesses and expect to explore potential strategic partner financing, commercial ventures or assets sales to enhance our liquidity and financial flexibility.

We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash generated from certain sales and financing transactions and cash generated from operations .

As part of preparing the financial statements included in this Quarterly Report, we have evaluated whether conditions exist that give rise to substantial doubt as to the ability of the Company to continue as a going concern.

During the first quarter of 2025, we recognized an operating loss and negative operating cash flows.

Our forecasted cash flows are expected to be impacted by, among other things, reduced earnings following the sale of the Jamaica Business that we anticipate will be replaced once projects in other jurisdictions are completed as well as increased interest expense resulting from the Refinancing Transactions completed in the fourth quarter of 2024.

As such, management has concluded, absent successfully executing on one or more of the strategies described below, that the Company’s current liquidity and forecasted cash flows from operations may not be sufficient to support, in full, obligations as they become due, and there is substantial doubt as to the Company’s ability to continue as a going concern.

Additionally, our 2026 Notes mature on September 30, 2026.

If more than $100 million of the 2026 Notes remain outstanding 91 days prior to this maturity date (the "Springing Maturity Date"), the outstanding principal of $2.7 billion under the New 2029 Notes becomes due.

If any of the 2026 Notes remains outstanding 91 days prior to the Springing Maturity Date, the outstanding balanced under the Revolving Facility, which was $750.0 million as of March 31, 2025, becomes due.

The aggregate principal amount of 2026 Notes outstanding as of March 31, 2025 is $510.9 million.

We are evaluating strategies to obtain the required additional funding for our future operations, including the following transactions that are excluded from our forecast, among other things:

(1) settlement of our claims resulting from the termination of the emergency power services contract in Puerto Rico in the first quarter of 2024, (2) realization of up to $110.0 million in proceeds from the modification of Genera’s Operation and Maintenance Agreement;

(3) receipt of proceeds from the Jamaica Sale that are currently in escrow of approximately $98.6 million;

and (4) expected cash flows from new business in Puerto Rico and Brazil.

Additionally, we continue to evaluate asset sales, capital raising, debt amendments and refinancing transactions and other strategic transactions that seek to optimize the value of our portfolio while providing additional liquidity and cash flow.

We also have the ability to support our liquidity position by delaying certain discretionary payments, including planned capital expenditures and dividends.

There are inherent uncertainties, as the occurrence of the events and transactions described above are outside management’s control and therefore there are no assurances that these events and transactions will occur.

Furthermore, there are inherent risks with our ability to continue to implement plans in future periods that will support our liquidity position, such as its ability to further extend the terms of vendor payments and other obligations.

There can be no assurances that these transactions will sufficiently improve our liquidity needs or that we will otherwise realize the anticipated benefits.

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

The terms and conditions of our indebtedness include restrictive covenants that limit our ability to operate our business, incur or refinance our debt, engage in certain transactions, and require us to maintain certain financial ratios, among others, any of which may limit our ability to finance future operations and capital needs, react to changes in our business and in the economy generally, and to pursue business opportunities and activities.

Following the completion of Amendments and the Transactions, our ability to undertake these activities, including our ability to incur or refinance our debt, will be further limited.

Furthermore, the restrictions contemplated by certain of the Amendments require proceeds of certain asset sales to be used to pay down existing indebtedness.

Following the completion of the Refinancing Transactions in the fourth quarter of 2024, our ability to undertake these activities, including our ability to incur or refinance our debt, is further limited.

Furthermore, the restrictions contemplated by certain of the amendments to our Revolving Facility require proceeds of certain asset sales to be used to pay down existing indebtedness.

From time to time, we may seek to repay, refinance or restructure all or a portion of our debt or to repurchase our outstanding debt through, as applicable, tender offers, redemptions, exchange offers, open market purchases, privately negotiated transactions or otherwise.

Such transactions, if any, will depend on a number of factors, including prevailing market conditions, our liquidity requirements and contractual requirements (including compliance with the terms of our debt agreements), among other factors.

Our expectations of future liquidity needs and sources include numerous assumptions that are subject to various risks and uncertainties.

Refer to Note 2 – “Significant Accounting Policies” for further information on liquidity and “Item 1A.

Risk Factors” for risks and uncertainties that may cause our results to differ from our expectations, each in our Annual Report on Form 10-K.

Our remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, is approximately $881 million and includes remaining expenditures to complete our first Fast LNG project and our onshore liquefaction project at Altamira, as well as committed expenditures necessary to complete the Puerto Sandino Facility, Barcarena and PortoCem Power Plants.

This does not include any capital expenditures related to Klondike.

We have secured financing commitments to continue to develop our onshore Altamira project, Barcarena Power Plant and PortoCem Power Plant,

which represents approximately $942 million of our upcoming committed capital expenditures and includes upcoming long-term permanent financing in Brazil to fully fund all development costs of our PortoCem Power Plant.

This anticipated financing, as well as the New Brazil Notes, is included within our secured financing commitments.

We have secured financing

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commitments to continue to develop our Barcarena Power Plant and PortoCem Power Plant, which represents approximately $294 million of our upcoming committed capital expenditures.

We expect fully completed Fast LNG units to cost between $1.0 billion and $2.0 billion per unit on average.

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We may also enter into other financing arrangements to generate proceeds to fund our developments.

As of September 30, 2024, we have spent approximately $128.6 million to develop the Pennsylvania Facility.

As of March 31, 2025, we have spent approximately $128.6 million to develop the Pennsylvania Facility.

Approximately $22.5 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.

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We are committed to make cash payments in the future pursuant to certain contracts.

The following table summarizes certain contractual obligations, including principal and interest, in place as of September 30, 2024.

The following table summarizes certain contractual obligations, including principal and interest, in place as of March 31, 2025:

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

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Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report, and “—Long-Term Debt and Preferred Stock” .

The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of September 30, 2024.

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report.

The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of March 31, 2025.

A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties.

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As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above.

The New Notes issued pursuant to the Transactions will bear interest at the increased rate of 12.00% per annum compared with the 2025 Notes, the 2026 Notes and the 2029 Notes being refinanced, and will increase long-term debt obligations.

As the Transactions have not yet been completed, the increased debt and interest expense has not been included in the table above.

Purchase obligations

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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.

Certain LNG purchase commitments are subject to conditions precedent,

and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met.

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 September 30, 2024.

We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility, Barcarena Power Plant and PortoCem Power Plant.

Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.

Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met.

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 March 31, 2025 .

We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant and PortoCem Power Plant.

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included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.

Lease obligations

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

The following table summarizes the changes to our cash flows for the nine months ended September 30, 2024 and 2023, respectively :

Nine Months Ended September 30,

The following table summarizes the changes to our cash flows for the three months ended March 31, 2025 and 2024, respectively :

Three Months Ended March 31,

(in thousands of $) 2025 2024 Change

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Financing activities 204,456 157,617 46,839

Net decrease in cash, cash equivalents, and restricted cash $ (61,477) $ (604,306) $ 542,829

Cash provided by operating activities

Our cash flow provided by operating activities was $146.2 million for the nine months ended September 30, 2024, which increased by $391.0 million from cash provided by operating activities of $537.2 million for the nine months ended September 30, 2023.

Our net income for the nine months ended September 30, 2024, when adjusted for non-cash items, decreased by $150.7 million from the nine months ended September 30, 2023.

The remaining decrease in cash provided by operating activities for the nine months ended September 30, 2024 was primarily driven by increases to recoverable taxes presented in Other current assets, and decreases in accrued liabilities.

We also settled a commodity swap during the first quarter of 2023, resulting in a significant cash inflow that did not recur during 2024.

Net (decrease) increase in cash, cash equivalents, and restricted cash $ (163,164) $ 7,887 $ (171,051)

Cash (used in) / provided by operating activities

Our cash flow used in operating activities was $31.7 million for the three months ended March 31, 2025, which increased by $101.8 million from cash provided by operating activities of $70.1 million for the three months ended March 31, 2024.

Our net loss for the three months ended March 31, 2025, when adjusted for non-cash items, increased by $358.5 million from the three months ended March 31, 2024.

The increase in net loss when adjusted for non-cash items was offset by increases to accounts payable and other changes in working capital.

Cash used in investing activities

Our cash flow used in investing activities was $1,308.6 million for the nine months ended September 30, 2024, which decreased by $757.0 million from cash used in investing activities of $2,065.6 million for the nine months ended September 30, 2023.

Cash outflows for investing activities during the nine months ended September 30, 2024 were used primarily for continued development of our Fast LNG project and the construction of the PortoCem Power Plant and Barcarena Power Plant.

Our cash flow used in investing activities was $335.9 million for the three months ended March 31, 2025, which increased by $116.1 million from cash used in investing activities of $219.8 million for the three months ended March 31, 2024.

Cash flows from investing activities during the three months ended March 31, 2025 were used primarily for continued development of our onshore FLNG project and the construction of the PortoCem Power Plant.

Cash outflows for investing activities during the three months ended March 31, 2024 were used primarily for the continued development of our Fast LNG project and construction of our Barcarena Power Plant.

Cash outflows were offset by proceeds of $306.6 million from the sale of turbines and related equipment to PREPA, $136.4 million from the sale of our equity method investment in Energos and $22.4 million from the sale of the Mazo .

Cash outflows for investing activities during the nine months ended September 30, 2023 were used primarily for continued development of our Fast LNG project and assets to service the grid stabilization project in Puerto Rico.

Cash outflows were offset by proceeds of $100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange, as well as proceeds received from the sale of the Spirit and a portion of our investment in equity securities.

Cash provided by financing activities

Our cash flow provided by financing activities was $1,100.9 million for the nine months ended September 30, 2024, which increased by $176.8 million from cash provided by financing activities of $924.1 million for the nine months ended September 30, 2023.

Throughout the first nine months of 2024, we had total borrowings of $3,594.2 million, with such borrowings primarily used to fund continued development of the Fast LNG project, Barcarena Power Plant, and PortoCem Power Plant.

Such borrowings were also used to repay a portion of the 2025 Notes and various asset level financings in Puerto Rico and Brazil.

We also repaid our Revolving Facility and short-term borrowings under repurchase agreements, prior to again drawing on these facilities.

Our cash flow provided by financing activities for the nine months ended September 30, 2023 included a dividend payment of $626.3 million that was made in January 2023.

Throughout the first nine months of 2023, we also borrowed under our expanded Revolving Facility, Bridge Term Loans, Equipment Notes, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $1,768.7 million.

Such borrowings were primarily used to fund the ongoing development of our Fast LNG project and to support our grid stabilization project in Puerto Rico.

Increased borrowings during 2023 were offset by repayments of debt totaling $104.5 million, primarily the repayment of short-term borrowings under repurchase arrangements.

Long-Term Debt and Preferred Stock

Our cash flow provided by financing activities was $204.5 million for the three months ended March 31, 2025, which increased by $46.8 million from cash provided by financing activities of $157.6 million for the three months ended March 31, 2024.

During the three months ended March 31, 2025 we had total borrowings of $943.6 million, with such borrowings primarily used to fund continued development of the onshore FLNG project and for other corporate expenses .

Such borrowings were also used to repay the Barcarena Debentures in full .

We also repaid our Revolving Facility by $275.0 million.

In the first quarter of 2024 we issued $750.0 million of 2029 Notes with such borrowings primarily used to repay $375.0 million of the 2025 Notes and repay a portion of our outstanding balance on the Revolving Facility.

In advance of the sale of turbines to PREPA, we also repaid the Equipment Notes in full.

Subsequently, we utilized our Revolving Facility to fund continued development of the Fast LNG project.

We also received $284.4 million under the BNDES Credit Agreement, with such borrowings primarily used to repay the Barcarena Term Loan and fund development of the

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Barcarena Power Plant.

We also paid dividends of $32.3 million during the first quarter of 2024.

Under certain intercompany agreements entered into in conjunction with the Refinancing Transactions completed in the fourth quarter of 2024, New Fortress Energy Inc.

is no longer permitted to pay dividends to shareholders.

Long-Term Debt

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 and as contemplated under "Recent Developments".

2029 Senior Secured Notes

In March 2024, we issued $750.0 million of 8.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2029 Notes”).

Interest is payable semi-annually in arrears on March 15 and September 15 of each year;

no principal payments are due until maturity on March 15, 2029.

We may redeem the 2029 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2029 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2025 Notes and 2026 Notes, and the 2029 Notes are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes.

The 2029 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 conditions and qualifications.

The 2029 Notes also provide for customary events of default and prepayment provisions.

In connection with the offering of the 2029 Notes, we completed a cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes, for an aggregate repurchase price of $376.9 million.

The tender offer was closed and the partial repurchase of the 2025 Notes was completed in the first quarter of 2024.

The premium over the repurchase price of $1.9 million was recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) .

BNDES Term Loan

One of our subsidiaries, the owner of t he Barcarena Power Plant, entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement").

We are able to borrow up to $355.6 million under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan").

In the first quarter of 2024, we borrowed $284.4 million under the BNDES Credit Agreement.

In the third quarter of 2024, we borrowed $60.3 million under the BNDES Credit Agreement.

Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES.

No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045.

Interest payments prior to April 2026 are made through an increase in the outstanding principal amount and are due quarterly thereafter.

The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's power purchase agreements.

These Brazilian subsidiaries must adhere to customary affirmative and negative

covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.

Proceeds received were used to repay the existing Barcarena Term Loan (defined in the Annual Report) and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025.

In February 2024, we repaid the full outstanding principal balance of the Barcarena Term Loan, fully extinguishing the obligation.

No material loss on extinguishment was recognized in conjunction with this repayment.

EB-5 Loan Agreement

On July 21, 2023, we entered into a loan agreement under the U.S.

Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas.

The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100.0 million, and outstanding borrowings bear interest at a fixed rate of 4.75%.

The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods.

It is expected that the loan will be secured by our green hydrogen facility, and we have provided a guarantee of the obligations under the EB-5 Loan Agreement.

In the nine months ended September 30, 2024, an additional $37.1 million was funded under the EB-5 Loan Agreement.

PortoCem Financings

As part of the PortoCem Acquisition, we assumed a term loan in the aggregate principal amount of R$141.4 million ($28.1 million based on rates in effect on the acquisition date) due December 2024, bearing interest at a rate equal to the one-day interbank deposit rate in Brazil plus 5.0% (the “PortoCem BTG Loan”).

Lenders under the PortoCem BTG Loan waived acceleration requirements in the event of a change in control in conjunction with the PortoCem Acquisition, and repayment of the PortoCem BTG Loan was required upon the earlier of PortoCem obtaining additional financing or the original maturity date of December 2024.

In April 2024, PortoCem and a syndicate of banks in Brazil entered into a commitment letter for R$2.9 billion of financing.

PortoCem received funding under a short term credit note of R$600.0 billion million ("PortoCem Credit Note") from this syndicate that was due in July 2024, and a portion of the proceeds was used to repay the PortoCem BTG Loan.

In May 2024, the PortoCem Credit Note was replaced by a bridge financing agreement that allows PortoCem to borrow up to R 2.9 billion due in October 2025 ("PortoCem Bridge Loan").

PortoCem initially borrowed R$ 1.5 billion ($ 275.3 million based on rates in effect at September 30, 2024), and this initial funding was used to repay the PortoCem Credit Note and to begin the development and construction of the PortoCem Power Plant.

The PortoCem Bridge Loan bears interest at the one-day interbank deposit futures rate in Brazil plus 4.25% , and no principal payments are required until maturity in October 2025.

The PortoCem Bridge Loan contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

The PortoCem Bridge Loan does not contain any restrictive financial covenants.

Turbine Financing

In May 2024, we executed a loan agreement with a lender to borrow $148.5 million million under a promissory note secured by certain of our turbines (the “Turbine Financing”).

The Turbine Financing bears interest at 10.30% , and the principal is partially repayable in monthly installments over the 36-month term of the loan with the balance due upon maturity in June 2027.

The Turbine Financing contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

The Turbine Financing does not contain any restrictive financial covenants.

We were required to pay a deposit of approximately $6.0 million that will be held by the lender throughout the term of the borrowing.

Equipment Notes

In conjunction with the execution of the APA to sell certain turbines to PREPA in March 2024, we repaid the Equipment Notes in full, releasing any liens held on the turbines prior to their sale.

Principal outstanding as of the repayment date was $188.4 million, and we incurred a prepayment premium of 3%.

The prepayment premium and any

unamortized financing costs of $7.9 million were recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss).

In July 2024, we entered into a credit agreement ("Term Loan A Credit Agreement") for a senior secured, multiple draw term loan facility in an aggregate principal amount of up to $700.0 million ("Term Loan A").

Proceeds will be used to pay costs of the construction and development of our onshore FLNG project in Altamira (the “Altamira Onshore Project”).

The initial and subsequent funding of the Term Loan A was subject to certain conditions, including the condition to the initial funding that initial generation of LNG from the offshore FLNG facility at Altamira ("FLNG1 Project") had been achieved.

Such condition was satisfied and initial funding occurred in the third quarter of 2024.

The remaining commitments for subsequent funding expire on the earliest of June 30, 2026, the date of completion of the Onshore Altamira Project (the “Completion Date”) and the date that the commitments are reduced to zero or terminated.

During the third quarter of 2024, we drew $285.8 million on the Term Loan A.

The obligations under the Term Loan A Credit Agreement are guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2025 Notes, 2026 Notes, 2029 Notes, our Revolving Facility, our letter of credit facility (the “Letter of Credit Facility”) and our Term Loan B, other than the guarantors comprising the FLNG1 Project (who guarantee the Revolving Facility, the Letter of Credit Facility, and the Term Loan B).

The obligations under the Term Loan A Credit Agreement are secured by substantially the same collateral as the collateral securing such facilities, with the exception of the collateral comprising the FLNG1 Project (which secures the Revolving Facility, the Letter of Credit Facility, and the Term Loan B).

Additionally, the Term Loan A is guaranteed by the entities, and secured by the assets, comprising the Onshore Altamira Project.

An equal priority intercreditor agreement governs the treatment of the collateral.

The Term Loan A will mature in July 2027 and is payable in full on maturity date.

In the event that the our existing 2025 Notes or 2026 Notes are not refinanced or repaid at least 60 days prior to their respective maturities, amounts outstanding under the Term Loan A will become due and payable on such date.

We may prepay the Term Loan A at its option without premium or penalty at any time subject to customary break funding costs.

We are required to prepay the Term Loan A with the net proceeds of certain asset sales, condemnations, debt and convertible securities issuances, and extraordinary receipts related to the Onshore Altamira Project.

Additionally, commencing with the first fiscal quarter after the Completion Date, we will be required to prepay the Term Loan A with the Onshore Altamira Project’s Excess Cash Flow (as defined in the Term Loan A Credit Agreement).

The Term Loan A will bear interest at a per annum rate equal to Term SOFR plus 3.75%, or at a base rate of 2.75%.

The interest rate on the Term Loan A will increase by 0.25% every 180 days beginning in June 2025.

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

Term Loan B Credit Agreement

In March 2025, we entered into an amendment to the Term Loan B Credit Agreement.

Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425.0 million, which increased the total outstanding principal amount to $1,272.4 million ("Term Loan B").

The incremental term loans were issued at a discount, and we received proceeds, net of discount, of $391.0 million.

Net proceeds will be used primarily to fund capital expenditures of the onshore FLNG project, and for other corporate expenses.

The incremental term loans are subject to the same maturity date as the term loans under the original agreement.

Quarterly principal payments of approximately $3.2 million are required beginning June 2025.

The Term Loan B is secured by the same collateral as that secured the term loans under the original agreement.

The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the amendment) plus 5.5%.

We may prepay the Term Loan B at its option subject to prepayment premiums until March 10, 2028 and customary break funding costs.

We are required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances and with our Excess Cash Flow (as defined in the amendment), in each case subject to certain exceptions and thresholds.

We must comply with the same covenant requirements as those under the original agreement.

The Term Loan B Credit Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

No financial covenant compliance is required under the Term Loan B Credit Agreement.

Term Loan A Credit Agreement

In March 2025, we entered into an amendment to the Term Loan A Credit Agreement.

Pursuant to the amendment, the future borrowing commitments are reduced to zero, eliminating the potential for future borrowings under the Term Loan A Credit Agreement.

The Term Loan A Credit Agreement contains usual and customary representations, warranties and affirmative and negative covenants for financings of this type, including certain representations and warranties related to the Onshore Altamira Project.

The Term Loan A Credit Agreement includes certain other covenants related solely to the Onshore Altamira Project, including limitations on capital expenditures, restrictions on additional accounts, and restrictions on amendments or termination of certain material documents related to the Onshore Altamira Project.

We must also comply with certain financial covenants.

Debt and lease restrictions

We are 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 4.0:1.0.

On August 31, 2024, we entered into amendments of certain debt agreements that amend and restate the conditions applicable to the suspension of the maximum Debt to Total Capitalization Ratio for the quarterly covenant tests conducted as of the last day of the fiscal quarters ending September 30, 2024, December 31, 2024 and March 31, 2025.

The amended agreements also contain a financial covenant that requires a minimum consolidated liquidity of (i) $50.0 million as of the last day of each month, commencing as of October 31, 2024 and (ii) $100.0 million as of the last day of any fiscal quarter, commencing as of December 31, 2024.

We were in compliance with all covenants as of September 30, 2024 .

We must also comply with certain financial covenants consistent with those under the Revolving Facility, including Debt to EBITDA Ratio and minimum consolidated liquidity.

Brazil Financing Notes

In February 2025, one of our consolidated subsidiaries entered into an agreement to issue up to $350.0 million aggregate principal amount of 15.0% Senior Secured Notes due 2029 (the “Brazil Financing Notes”) at a purchase price of 97.75% of par.

The Brazil Financing Notes mature on August 30, 2029;

the principal is due in full on the maturity date.

Interest is payable quarterly in arrears beginning on June 30, 2025, and for the first 30 months that the Brazil Financing Notes are outstanding, interest due can be paid in kind and added to the principal amount.

A portion of the proceeds from the issuance of the Brazil Financing Notes of $208.7 million was used to repay the Barcarena Debentures in full.

The Brazil Financing Notes contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

No financial covenant compliance is required under the Brazil Financing Notes.

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Critical Accounting Policies and Estimates

A complete discussion of our critical accounting policies and estimates is included in our Annual Report.

As of September 30, 2024 , there have been no significant changes to our critical accounting estimates since our Annual Report.

As of March 31, 2025 , there have been no significant changes to our critical accounting estimates since our Annual Report.

Recent Accounting Standards

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What changed 10-Q

Item 2. Management’s Discussion and Analysis