New Fortress Energy Inc. (NFE)

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

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors.

You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The comparison of the years ended December 31, 2023 and 2022 can be found in our Annual Report on Form 10-K for the year ended December 31, 2023 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.

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

Overview

We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in this Annual Report, “Items 1 and 2: 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. Our first floating liquefaction unit, which we refer to as "Fast LNG" or "FLNG", began producing LNG in July 2024, and, once fully commissioned, we plan to source a portion of our LNG needs from this facility. 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 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 included in our Terminals and Infrastructure segment.

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Our Current Operations – Terminals and Infrastructure

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, 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 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

Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant, 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 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 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 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 to PREPA. The contract initially has a one year term that is renewable annually for three additional annual periods.

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.

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

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improving reliability of power generation in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees. The service period under the contract commenced on July 1, 2023.

La Paz Facility

In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power. We placed the La Paz Power Plant into service in the third quarter of 2023.

In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. 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.

Santa Catarina Facility

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 upcoming power auctions in Brazil scheduled for June 2025, and to the extent that we are successful in these auctions, we expect to develop a gas-fired power plant using natural gas from the Santa Catarina Facility.

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 closed in the fourth quarter of 2024.

Our LNG Supply and Cargo Sales

NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 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 TBtus 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 Montego Bay Facility, Old Harbour Facility, 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 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, 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 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 included in 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. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. 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. 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; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos.

Our Development Projects

Our projects currently under development include our development of a series of modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); 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"). We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.

The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.

We describe each of our current development projects below.

Fast LNG

We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. Our first “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 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.

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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Altamira

Our first Fast LNG unit has been deployed off the coast of Altamira, Tamaulipas, Mexico. 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. Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in the process of finalizing commissioning the project. While we experienced delays in commissioning our first FLNG unit, which impacted our results of operations in 2024 and may impact our results in future periods, in July 2024, we began to produce LNG. We have placed this asset into service from an accounting perspective in the fourth quarter of 2024, and we expect to achieve run-rate production in 2025.

We expect to deploy up to two 1.4MTPA additional FLNG units onshore at the existing Altamira LNG import facility. The terminal would source also 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. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks.

Louisiana

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. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.

Lakach

We have been in discussions with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. Our initial agreements were terminated in the fourth quarter of 2023, however, NFE continues to be in active discussions with Pemex to develop or monetize an offshore project.

Puerto Sandino Facility

We are developing a liquefied natural gas receiving, transloading and regasification facility in Puerto Sandino, Nicaragua, as well as a pipeline connecting the facility with our Puerto Sandino Power Plant. 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. 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 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.

The Barcarena Facility will also supply our new 630MW combined cycle natural gas-fired power plant to be 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 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 is the owner of a 15-year 1.6GW capacity reserve contract in Brazil. 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

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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

We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026.

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 permit. In November, ABP sought leave to appeal the High Court's decision, the High Court has not yet heard the request to leave appeal. If the leave is not granted, ABP will be directed to reconsider our permit application on 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.

ZeroParks

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. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies.

Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the western hemisphere and numerous petrochemical manufacturers, many of which require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect ZeroPark I to be the largest green hydrogen plant in the United States.

Klondike

We recently 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 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 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, 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

In February 2025, one of our consolidated subsidiaries entered into an agreement to issue up to $350.0 million aggregate principal amount of 15% Senior Secured Notes due 2029 (the “Brazil Financing Notes”) at a purchase price of 97.75% of par. The Brazil Financing Notes bear interest at a rate of 15.0% and mature on August 30, 2029; the principal is due in full on the maturity date. Interest is payable quarterly in arrears beginning on March 30, 2025, and for the first 30 months that

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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 was used to repay the Barcarena Debentures in full.

In March 2025, we entered into an amendment to the Term Loan B Agreement. Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425.0 million. The incremental term loans are subject to the same terms as the initial Term Loan B, including interest rates and maturity date. Net proceeds will be used primarily to fund capital expenditures of our onshore Fast LNG project at Altamira, and for other corporate expenses. In connection with the amendment, all unused term loan commitments under the Term Loan A Credit Agreement were terminated.

On March 6, 2025, we entered into a Backstop Agreement (the "Backstop Agreement") with a lender, pursuant to which we may, at our sole option, issue and sell to this lender (subject to the satisfaction of certain conditions) senior debt securities up to an aggregate principal amount sufficient to generate gross proceeds of $100.0 million with a term of at least three years from the closing date. Proceeds received would be used to satisfy the repayment of the outstanding borrowings under the Revolving Facility (defined below) required by the reduction of commitments by September 30, 2025. The Backstop Agreement would be terminated in the event that we complete the sale of assets or receives proceeds associated with a contract termination fee sufficient to satisfy such required repayment.

Other Matters

On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue.

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, 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.

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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 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 from an accounting perspective 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 this development.

While the asset is in service from an accounting perspective, we will continue to commission the asset to achieve run rate production. Such costs that enhance the asset will be capitalized on our Consolidated Balance Sheets.

•Our historical financial results do not reflect our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 93% of our LNG volumes from third parties for the year ended December 31, 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 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. We sold the first full cargo from this facility on September 30, 2024, and we anticipate reaching run rate production in 2025..

•Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2024 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. 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. 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.

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Results of Operations – Three Months Ended December 31, 2024 compared to Three Months Ended September 30, 2024 and Year Ended December 31, 2024 compared to Year Ended December 31, 2023

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. 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. 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.

Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. 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 December 31, 2024 and September 30, 2024, and for the year ended December 31, 2024 and December 31, 2023:

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(1)Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are an economic hedge of commodity purchases and sales, and a realized gain of $139.1 million for the year ended December 31, 2023 was recognized as a reduction to Cost of sales in the segment measure. We recognized unrealized losses of $106.4 million on the mark-to-market value of derivative transactions for the year ended December 31, 2023, and these losses reconcile Cost of sales in the segment measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. No realized gains or losses were recognized for the year ended December 31, 2024.

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 year ended December 31, 2023 reconcile Cost of sales in the segment

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measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. We did not incur such costs in the year ended December 31, 2024.

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

(3)For the year ended December 31, 2024, Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $150.0 million which were recognized during the third and fourth quarters of 2024.

In 2023, the effective share of revenues, expenses and operating margin attributable to our ownership of the common units of Hilli LLC were included in the segment measure prior to the disposition of this investment. Unrealized mark-to-market gains or losses on derivative instruments and the exclusion of non-capitalizable contract acquisition costs were also removed.

(4)Deferred earnings from contracted sales represent forward sales transactions that were contracted in the second and third quarters of 2024 and prepayment for these sales was received. Revenue has been recognized in the Consolidated Statements of Operations and Comprehensive (Loss) Income during the third and fourth quarters of 2024.

(5)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 as defined under GAAP.

Terminals and Infrastructure Segment

Total revenue

Total revenue for the Terminals and Infrastructure Segment increased by $46.7 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024. The increase was primarily driven by income from the novation of an LNG supply contract during the fourth quarter of 2024 and higher Henry Hub index pricing, offset by lower volumes delivered and cargo sales.

•The Company novated an LNG supply contract to a customer, recognizing $235.6 million within segment revenue in the fourth quarter. NFE recognized $60.0 million of deferred earnings from contracted sales with this customer

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in the third quarter of 2024, and this prepayment is included in the reconciliation between segment revenue and consolidated revenue recognized.

•The average Henry Hub index pricing used to invoice our downstream customers increased by 29% for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024.

•Volumes delivered to downstream terminal customers decreased from 20.7 TBtu in the third quarter of 2024 to 18.4 TBtu in the fourth quarter of 2024. The decrease was due to vessel maintenance in our LNG supply chain that briefly deferred deliveries to our customers.

•Revenue recognized from cargo sales decreased during the three months ended December 31, 2024 to $91.9 million from $174.5 million during three months ended September 30, 2024.

•In the second and third quarters of 2024, we recognized an estimate of the incentive fees that we expected to earn under our contract with Genera. In the first quarter of 2025, we modified our agreement with Genera to remove all future incentive payments in exchange for a payment of $110.0 million. The subsequent modification of the agreement required us to evaluate the incentive fees recognized in 2024, and we recognized a reversal of $57.0 million of revenue that was recognized earlier in 2024.

Total revenue for the Terminals and Infrastructure Segment decreased by $96.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, and segment revenue was impacted by the following in 2024:

•For the year ended December 31, 2024, volumes delivered to downstream customers were 81.3 TBtu as compared to 68.3 TBtu for the year ended December 31, 2023. We placed the La Paz Power Plant into service during the third quarter of 2023, and recorded a full year of revenue during 2024 compared to two quarters of revenue during 2023.

•During 2024, we recognized $235.6 million of income within segment revenue from the novation of an LNG supply contract.

•Starting in the third quarter of 2023, Genera, began to provide operations and maintenance services to PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue. The Company provided full year of operations and maintenance services during 2024 compared to six months of services in 2023.

Although we recognized the contract novation income and 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 17% for the year ended December 31, 2024 as compared to the year ended December 31, 2023.

•The Company had $291.0 million in cargo sales for the year ended December 31, 2024. Revenue from cargo sales was $618.5 million for the year ended December 31, 2023, which included $332.0 million of contract settlements.

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

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 sale of our Miami Facility, we continue sourcing LNG from third parties and we expect a portion of our supply to be generated by our first FLNG unit. 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. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide operations and maintenance services to

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PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue.

Cost of sales decreased $36.9 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024.

•We delivered 11% lower volumes to our customers in the fourth quarter. Our cost of LNG to supply our downstream customers increased by $8.6 million during the three months ended December 31, 2024, due to higher cost of gas purchased at $8.75 per MMBtu for the three months ended December 31, 2024 compared to $6.65 per MMBtu for the three months ended September 30, 2024.

•The higher cost of LNG to deliver to downstream customers was partially offset by lower cost of selling cargos. We incurred $35.6 million less cost of selling cargos during the fourth quarter of 2024 compared to the third quarter of 2024.

Cost of sales increased by $299.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, which was attributable to the following activity:

•We incurred increased cost of LNG to supply our downstream customers of $64.5 million during the year ended December 31, 2024 due to increased volumes delivered. We delivered 19% more volume to our downstream terminal customers in the current period. Our pricing to purchase LNG for delivery to such customers was slightly lower at $7.20 per MMBtu for the year ended December 31, 2024 compared to $7.23 per MMBtu for the year ended December 31, 2023.

•Vessel costs increased by $67.0 million, for the year ended December 31, 2024 as compared to the year ended December 31, 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 $101.4 million to provide services under Genera's operations and maintenance contract for the year ended December 31, 2024 compared to $35.6 million for the year ended December 31, 2023; these costs are passed onto PREPA. Only six months of such costs were incurred during the year ended December 31, 2023 as our contract commenced on July 1, 2023.

•We incurred decreased cost of LNG for cargo sales during the year ended December 31, 2024 by $19.2 million as our LNG cargo sale activity has been marginally lower in 2024.

•In the year ended December 31, 2023, realized gains of $139.1 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 2024.

The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 2024 and December 31, 2023 was $6.90 per MMBtu and $7.33 per MMBtu, respectively.

Operations and maintenance

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

Operations and maintenance increased by $2.3 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024. We incurred additional operations and maintenance costs for planned maintenance at our terminals and power plants during the three months ended December 31, 2024.

Operations and maintenance increased by $7.5 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. We incurred full year of operations and maintenance costs at our La Paz Power Plant in 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. The increase in costs were partially offset by lower lease costs

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incurred in 2024. The Company's contract to provide emergency power services to support the grid stabilization project was terminated in the first quarter of 2024 resulting in decreased lease expense compared to 2023.

Deferred earnings from contracted sales

In the second and third quarters of 2024, we completed forward sales receiving prepayments from the buyers of $90.0 million and $60.0 million respectively. The prepayments were 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 have been recognized in our Consolidated Statements of Operations and Comprehensive (Loss) Income in the third and fourth quarters of 2024, and as such, these deferred earnings do not impact the total segment operating margin recognized for the year ended December 31, 2024.

Ships Segment

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 December 31, 2024, three vessels included in the Energos Formation Transaction were leased to customers under long-term arrangements and are included in this segment.

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

Total revenue

Total revenue for the Ships segment remained consistent from the three months ended September 30, 2024 to the three months ended December 31, 2024 with a small decrease of $0.7 million.

Total revenue for the Ships segment decreased by $123.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 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, and one vessel in 2024, lowering vessel revenue for the year ended December 31, 2024. We are now utilizing these vessels in our operations.

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. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time

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charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.

Vessel operating expenses remained consistent between the three months ended September 30, 2024 and the three months ended December 31, 2024.

Vessel operating expenses decreased by $18.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 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. We started using four vessels in 2023 and one vessel in 2024 that were in the Ships segment, in our terminal operations, resulting in lower vessel operating costs.

Other operating results

Selling, general and administrative

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

Selling, general and administrative for the three months ended December 31, 2024 decreased by $20.6 million as compared to the three months ended September 30, 2024. The decrease was primarily driven by significant forfeitures of RSUs due to employee terminations, as well as, reduction in non-capitalizable development costs and payroll costs.

Selling, general and administrative increased by $80.4 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase was primarily due to higher share-based compensation expense and screening costs. During 2024, we granted RSUs to select officers, employees and certain non-employees, and an equity award to

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certain employees that will settle in shares of a subsidiary owning the Company's Brazilian operations. The Company recognized $50.4 million of share-based compensation expense for RSUs and other equity awards during the year ended December 31, 2024; no significant cost was recognized in the year ended December 31, 2023. In addition, the bad debt expense increased by $15.9 million for additional allowance and write-off of receivables during 2024. We also incurred higher screening costs for our development projects during 2024, offset by lower travel, payroll costs and professional fees.

Transaction and integration costs

The transaction and integration costs of $6.0 million and $12.3 million during the three months and year ended December 31, 2024, respectively, primarily relate to legal fees and other third party costs incurred by the Company in connection with the amendments of credit agreements.

Depreciation and amortization

Depreciation and amortization increased by $3.4 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024. The increase during the fourth quarter of 2024 was mostly attributable to additional depreciation of capitalized vessel-related costs.

Depreciation and amortization decreased by $25.3 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. During 2024, the Company sold turbines and related equipment to PREPA, resulting in a lower depreciation and amortization expense compared to the year ended December 31, 2023. Amortization of favorable vessel charter contracts also decreased in 2024 due to the expiration of charter contracts. The decrease in depreciation and amortization expense was partly offset by additional depreciation and amortization expense relating to PortoCem Acquisition and the La Paz Power Plant that was put into service during third quarter of 2023.

Asset impairment expense

For the year ended December 31, 2024 the Company recognized an impairment loss of $16.0 million related to the sale of our Miami facility, which includes an allocation of goodwill of $10.4 million. During year ended December 31, 2023, we recognized an impairment expense of $10.9 million for the vessel Mazo.

Loss (gain) on sale of assets, net

The Company had no significant asset sales during the third and fourth quarters of 2024. In 2023, we sold the vessel Golar Spirit and 100% of shares of Pecém and Muricy resulting in a total gain of $29.3 million. During 2024, the Company recognized a loss of $77.6 million from the sale of turbines and related equipment to the PREPA.

Interest expense

Interest expense increased by $28.4 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024, primarily due to additional deferred financing costs and higher interest rate under new and refinanced borrowings.

Interest expense increased by $50.5 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The increase was primarily due to an increase in total principal outstanding for additional borrowings and amortization of related debt issuance costs, net of capitalized interest cost. The total principal balance on outstanding facilities was $9.0 billion as of December 31, 2024 as compared to total outstanding debt of $6.9 billion as of December 31, 2023.

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Other expense (income), net

Other expense, net and other income, net was $52.4 million and $5.8 million for the three months ended December 31, 2024 and September 30, 2024, respectively. Other expense, net was $113.1 million and $10.4 million for the year ended December 31, 2024 and December 31, 2023, respectively.

Other expense, net recognized in the three months ended December 31, 2024 was primarily comprised of foreign currency loss due to remeasurement of USD denominated debt in our Brazil subsidiary. The losses were partly offset by interest income, and realized and unrealized gains on foreign currency derivative contracts.

Other expense, net recognized in the year ended December 31, 2024 was primarily comprised of remeasurement losses from USD denominated foreign currency debt in Brazil, resulting from depreciation of the BRL currency. The losses were partially offset by interest income and realized and unrealized gains on foreign currency derivative contracts.

Loss on extinguishment of debt

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. In Brazil, we repaid the PortoCem Bridge Loan with proceeds from the PortoCem Debenture issuance and recorded a loss on extinguishment of $25.0 million.

In addition, during the first quarter of 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes. During the same period, 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 2023.

Income (loss) from equity method investments

During 2023, we recognized income of $10.0 million from our equity method investment in Energos. 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 year ended December 31, 2024.

Tax provision

We recognized a tax provision of $69.5 million for the year ended December 31, 2024 compared to a tax provision of $115.5 million year ended December 31, 2023. For the year ended December 31, 2024, the tax provision was primarily driven by U.S. tax on earnings of our Puerto Rican operations and increases in valuation allowances against losses generated by our foreign operations in Brazil and Mexico.

Liquidity and Capital Resources

In the fourth quarter of 2024, we entered into a series of debt and equity transactions to extend the maturities of our corporate debt and to provide additional liquidity. In October, we issued 46,349,942 shares of our Class A common stock, at a purchase price to the public of $8.63 per share, less underwriting discounts and commissions, in a registered public offering, receiving net proceeds of approximately $387 million after underwriters' discounts, commissions and offering expenses. We also completed the Refinancing Transactions under which we issued approximately $2.7 billion of New 2029 Notes, repaid in full our 2025 Notes and repaid a portion of the 2026 Notes and 2029 Notes (each defined below), along with receiving approximately $300 million in proceeds. We also amended the terms of our Revolving Facility to extend the maturity of the majority of the commitments. Collectively these transactions extended the maturity of our corporate debt while providing additional liquidity to fund our development projects, including the completion of our first FLNG project.

We have made significant progress in extending the maturities of our long-term debt, and we continue to explore asset sales, settlement of claims and other strategic transactions (the "Transactions") that seek to optimize the value of our portfolio while providing additional liquidity and cash flow. As part of preparing the financial statements included in this Annual Report, we are required to consider the guidance in ASC 205-40, which requires us to only consider the mitigating effects of our plans only if those plans are fully implemented at the assessment date when assessing whether substantial doubt is raised about our ability to continue as a going concern. Under this guidance, we were required to exclude the effects of the Transactions from our forecast, and as such, we concluded that our current liquidity and forecasted cash flows from operations are not sufficient to support, in full, obligations as they become due. We have approved a plan to alleviate

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liquidity risk and concluded that we will have sufficient liquidity to meet its obligations as they become due over the next twelve months from the date that the consolidated financial statements were issued.

Additionally, we expect our current working capital position to improve based on the following: (1) funding received from our Brazil Financing Notes and our upsized Term Loan B; (2) expected cash flows generated from new gas sale agreements and volume growth in Puerto Rico, Mexico and Brazil; (3) sales of our own LNG generated by our first deployed Fast LNG unit; (4) continued proceeds from our asset sale program; and (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. 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 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 the Refinancing Transactions, 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 remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, is approximately $1,159 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 Barcarena Power Plant and PortoCem Power Plant, which represents approximately $433 million of our upcoming committed capital expenditures. In February 2025, we issued the Brazil Financing Notes raising $350.0 million, and in March 2025, we upsized the Term Loan B by an additional $425.0 million. Proceeds received from these financings can be used for general corporate purposes, including towards our development projects.

We expect fully completed Fast LNG units to cost between $1.0 billion and $2.0 billion per unit on average. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to construct the Fast LNG units allow us to closely control the timing of our spending and construction schedules so that we can complete each project in time frames to meet our business needs. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.

As of December 31, 2024, 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. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106.1 million, has been capitalized, and to date, we have repurposed approximately $16.8 million of engineering and equipment to our Fast LNG project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities.

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Contractual Obligations

We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2024:

Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2024. The principal on the PortoCem BNDES Debentures (defined below) is subject to adjustment based on inflation; the table above only includes the principal balance due as of December 31, 2024, and does not project future amounts that may be due based on inflation.

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. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. 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 New 2029 Notes 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 results in an increase in long-term debt obligations. The increased debt and interest expense has been included in the table above.

Purchase obligations

We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. 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 December 31, 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.

Lease obligations

Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, and a land lease.

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Cash Flows

The following table summarizes the changes to our cash flows for the year ended December 31, 2024 and 2023, respectively:

Cash provided by operating activities

Our cash flow provided by operating activities was $586.7 million for the year ended December 31, 2024, which decreased by $238.0 million from cash provided by operating activities of $824.8 million for the year ended December 31, 2023. Our results for the year ended December 31, 2024, when adjusted for non-cash items including loss on extinguishment of debt, decreased by $199.3 million from the year ended December 31, 2023. We also settled a commodity swap during the first quarter of 2023, resulting in a significant cash inflow that did not recur during 2024.

Cash used in investing activities

Our cash flow used in investing activities was $2,074.6 million for the year ended December 31, 2024, which decreased by $829.5 million from cash used in investing activities of $2,904.1 million for the year ended December 31, 2023. Cash outflows from investing activities during the year ended December 31, 2024 were used primarily for continued development of our Fast LNG project and the construction of the PortoCem Power Plant and Barcarena Power Plant. Cash outflows were offset by proceeds from the sale of assets including the sale of turbines and related equipment to PREPA, our investment in Energos, the Mazo and the Miami Facility.

Cash outflows for investing activities during the year ended December 31, 2023 were used 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, proceeds received from the sale of Pecém and Muricy, 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 $2,224.6 million for the year ended December 31, 2024, which increased by $695.6 million from cash provided by financing activities of $1,529.0 million for the year ended December 31, 2023. During the year ended December 31, 2024 we had total borrowings of $5,865 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 during the year ended December 31, 2023 included a dividend payment of $626.3 million that was made in January 2023. We have borrowed under our new Term Loan B Agreement, expanded Revolving Facility, Bridge Term Loans, Equipment Notes, Barcarena Debentures, EB-5 Loan, Tugboat Financing, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $3.0 billion. 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 $686.5 million, primarily the repayment of the Bridge Term Loans and short-term borrowings under repurchase arrangements.

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Long-Term Debt

2024 Exchange Transactions

On November 6, 2024, we entered into an exchange and subscription agreement (the “Exchange and Subscription Agreement”) with certain holders (the “Supporting Holders”) of our outstanding 2026 Notes and 2029 Notes (each defined below). Pursuant to the Exchange and Subscription Agreement (i) NFE Financing LLC (“NFE Financing”), an indirect subsidiary of NFE, sold to the Supporting Holders approximately $1,210.4 million aggregate principal amount of NFE Financing’s 12.0% Senior Secured Notes due 2029 (the “New 2029 Notes”) (the transactions described in clause (i), the “Subscription Transactions”) and (ii) NFE Financing issued to the Supporting Holders approximately $1,519.7 million aggregate principal amount of New 2029 Notes in a dollar-for-dollar exchange for a portion of our 2026 Notes and 2029 Notes (the transactions described in clause (ii), the “Exchange Transactions” and together with the Subscription Transactions, the “Refinancing Transactions”).

NFE Financing issued $2,730.1 million aggregate principal amount of New 2029 Notes pursuant to the Refinancing Transactions. We utilized $886.6 million of these net proceeds from the Subscription Transactions to repay in full the outstanding aggregate principal amount and accrued interest on the 2025 Notes. The remainder of the net proceeds from the New 2029 Notes issued pursuant to the Subscription Transactions will be used for general corporate purposes.

Pursuant to the Exchange and Subscription Agreement, upon consummation of the Refinancing Transactions, the Supporting Holders received a commitment fee equal to either (i) 5% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in shares of Class A common stock of the Company, 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 2029 Notes, payable in kind in the form of additional New 2029 Notes (the “Commitment Fee Notes”), or (iii) a combination of the foregoing. We have issued 15,700,998 Commitment Fee Shares to the Supporting Holders in satisfaction of its commitment fee obligations under the Exchange and Subscription Agreement, and $5.4 million Commitment Fee Notes were issued and included in the total New 2029 Notes issuance.

The New 2029 Notes were issued pursuant to, and are governed by, an indenture (the “New Notes Indenture”). The New 2029 Notes are senior, secured obligations of NFE Financing, and interest is payable semi-annually in arrears at a rate of 12.0% per annum on May 15 and November 15 of each year, beginning on May 15, 2025. The New Notes will mature on November 15, 2029, provided that the maturity date shall be accelerated to the date that is 91 days prior to the stated maturity date of any of our other indebtedness, subject to certain exceptions as described in the New Notes Indenture, if more than $100.0 million aggregate principal amount of such other indebtedness remains outstanding on such date.

NFE Financing may redeem some or all of the New 2029 Notes at redemption prices set forth in the New Notes Indenture; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. Further, upon the occurrence of certain other events, including change of control and certain distributions from our Brazil business, NFE Financing may be required to make an offer to repurchase all of the New 2029 Notes at prices specified in the New Notes Indenture.

The New 2029 Notes are guaranteed by NFE Financing’s wholly-owned subsidiary, Bradford County Real Estate Partners LLC (the “New Notes Guarantor”) which owns our land in Wyalusing, Pennsylvania. The New 2029 Notes are secured by first-priority liens on: (a) all assets of NFE Financing, including approximately 45% of the equity in the entity that owns our Brazil business, and 100% of the equity in the New Notes Guarantor and (b) all assets of the New Notes Guarantor.

The New Notes Indenture provides for customary events of default which include (subject in certain cases to customary grace and cure periods), among others, acceleration and/or defaults of certain of our other indebtedness. The New Notes Indenture and other credit agreements associated with certain intercompany loans of NFE Financing, limit our ability to, among other things, incur additional indebtedness, incur liens that secure indebtedness, make restricted payments, create dividend restrictions and other payment restrictions, sell or transfer certain assets, in each case subject to certain exceptions and qualifications set forth in the New Notes Indenture and other indentures.

The repayment of all of the 2025 Notes and the exchange of a portion of the 2026 Notes and 2029 Notes was treated as an extinguishment, and $11.4 million of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Fees paid to lenders, including the issuance of Commitment Fee Shares and Commitment Fee Notes, of $193.4 million were included in

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the loss on extinguishment of debt. We also recognized $30.5 million of loss on extinguishment of debt, which represents the fair value of the New 2029 Notes issued in excess of the carrying amount of debt exchanged or repaid. The New 2029 Notes are recorded at fair value and fees paid to third parties of $32.3 million will be amortized over the term of the New 2029 Notes.

In conjunction with the Refinancing Transactions, the Supporting Holders agreed to consent to certain amendments to the indentures pursuant to which the 2026 Notes (such indenture, the “Existing 2026 Notes Indenture”) and the 2029 Notes (such indenture, the “Existing 2029 Notes Indenture”) were issued. These amendments allow us to subordinate the liens on certain of the collateral securing the obligations under each of the Existing 2026 Notes Indenture and Existing 2029 Notes Indenture to the liens on the same collateral securing certain intercompany loans due to NFE Financing, and to remove all covenants and events of default that may be removed in compliance with terms of such indentures (the “Indenture Amendments”). The adoption of the Indenture Amendments required the consent of holders of at least 66.67% the outstanding principal amount of each of the 2026 Notes and 2029 Notes. We received the required level of consent, and subsequently executed a supplemental indenture to the Existing 2026 Notes Indenture (the “2026 Supplemental Indenture”) and a supplemental indenture to the Existing 2029 Notes Indenture (the “2029 Supplemental Indenture,” and, together with the 2026 Supplemental Indenture, the “Supplemental Indentures”) effecting the Amendments. The Supplemental Indentures became effective on December 5, 2024.

Series I Credit Agreement

On November 22, 2024, NFE Brazil Investments LLC (“Brazil Parent”), as lender, Wilmington Savings Fund Society, FSB, as the administrative agent and as collateral agent, New Fortress Energy Inc. , as borrower, and certain subsidiaries, as guarantors, entered into a senior secured, multiple-draw term loan credit agreement (“Series I Credit Agreement”) in an aggregate principal amount of approximately $970.0 million (the “Series I Term Loan Facility,” and the loans made under the Series I Term Loan Facility, the “Series I Term Loans”). The initial and subsequent funding of the Series I Term Loans are subject to certain customary conditions. The Series I Term Loans bear interest at a rate of 16.5997% (exclusive of 2.00% interest being paid-in-kind) per annum, payable semiannually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025. The cash interest rate on the Series I Term Loans will be reduced by an amount to be determined from and after the closing date of the Refinancing Transactions. On November 22, 2024, NFE borrowed $875.0 million of Series I Term Loans to redeem in full the outstanding aggregate principal amount of the 2025 Notes. On December 6, 2024, NFE borrowed the remaining $95.0 million of the Series I Term Loans, the proceeds of which were used to effectuate the transactions contemplated by the Exchange and Subscription Agreement.

The Series I Term Loans will mature on November 15, 2029 and will be payable in full on the maturity date. The obligations under the Series I Credit Agreement are 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 Credit Agreement are secured by substantially the same collateral as the collateral securing the 2026 Notes and the 2029 Notes. An equal priority intercreditor agreement governs the treatment of the collateral.

The Series I Term Loans may be voluntarily prepaid by NFE, in whole or in part, subject to prepayment premiums, as set forth in the Series I Credit Agreement; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. NFE will be required to prepay the Series I Term Loans upon the occurrence of any change of control (which shall include 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.

The Series I Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Brazil Parent Credit Agreement

On November 22, 2024, NFE Financing, as lender, entered into a credit agreement (the “Brazil Parent Credit Agreement”), with Brazil Parent, as the borrower, and Wilmington Savings Fund Society, FSB, as administrative agent and collateral agent.

The Brazil Parent Credit Agreement provides for a senior secured, multiple-draw term loan facility of approximately $970.0 million (the “Brazil Parent Term Loan Facility,” and the term loans made thereunder, the “Brazil Parent Term Loans”), which matures on November 15, 2029. The stated maturity date will be accelerated to a date that is 91 days prior to the stated maturity date of any other indebtedness for borrowed money (including indebtedness deemed issued in a debt

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exchange), excluding indebtedness under the amended uncommitted letter of credit and reimbursement agreement, if more than $100.0 million in aggregate principal amount of such indebtedness remains outstanding at such time. The initial and subsequent funding of the Brazil Parent Term Loans are subject to certain customary conditions. The Brazil Parent Term Loans bear interest at a rate of 16.5997% (exclusive of 2.00% interest being paid-in-kind) per annum, payable semiannually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025. The cash interest rate on the Brazil Parent Term Loans will be reduced by an amount to be determined from and after the closing of the Refinancing Transactions. The obligations under the Brazil Parent Credit Agreement are secured by substantially all assets of Brazil Parent (including a pledge of the equity interests held by Brazil Parent in NFE Brazil Holdings). On November 22, 2024, Brazil Parent borrowed $875.0 million of Brazil Parent Term Loans, the proceeds of which were advanced to us pursuant to the Series I Credit Agreement for the redemption in full of the outstanding aggregate principal amount of the 2025 Notes. On December 6, 2024, Brazil Parent borrowed the remaining $95.0 million from the Brazil Parent Term Facility. The proceeds of the Brazil Parent Term Loan were used to fund the Series I Term Loan Facility.

The Brazil Parent Term Loans may be voluntarily prepaid by Brazil Parent, subject to prepayment premiums as set forth in the Brazil Parent Credit Agreement; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. In addition, Brazil Parent will be required to prepay the Brazil Parent Term Loans upon the occurrence of certain events (subject to certain premiums as applicable and set forth in the Brazil Parent Credit Agreement), including any change of control and receipt of net proceeds from any prepayment under the Series I Credit Agreement.

The Brazil Parent Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Series II Credit Agreement

On December 6, 2024, NFE Financing, as lender, Wilmington Savings Fund Society, FSB, as the administrative agent and as collateral agent, and NFE, as borrower, and certain of our subsidiaries of NFE from time to time party thereto as guarantors, entered into a senior secured term loan credit agreement (“Series II Credit Agreement,” and together with the Series I Credit Agreement and the Brazil Parent Credit Agreement, the “Intercompany Credit Agreements”) in an aggregate principal amount of approximately $1.43 billion (the loan made under the term loan facility, the “Series II Term Loan”). The proceeds will be used by us to consummate the transactions contemplated by the Exchange and Subscription Agreement.

The Series II Term Loan will mature in November 2029 and is payable in full on the maturity date. The obligations under the 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 II Credit Agreement will be secured by substantially the same collateral as the collateral securing the 2026 Notes and the 2029 Notes. An equal priority intercreditor agreement will govern the treatment of the collateral.

The Series II Term Loans may be voluntarily prepaid by NFE, in whole or in part, subject to prepayment premiums, as set forth in the Series II Credit Agreement; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. NFE will be required to prepay the Series II Term Loan upon the occurrence of any change of control (which shall include 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.

The Series II Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

2025 Notes

In September and December 2020, we issued an aggregate amount of $1,250.0 million of 6.75% senior secured notes in private offerings pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest was payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments were due until maturity on September 15, 2025.

In connection with the offering of the 2029 Notes (defined below) in March 2024, 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

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the repurchase price of $1.9 million was recognized as Loss on extinguishment of debt, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The remaining outstanding principal under the 2025 Notes was repaid in conjunction with the Refinancing Transactions.

2026 Notes

In April 2021, we issued $1,500.0 million of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of each year; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2026 Notes are guaranteed, jointly and severally, on a senior secured basis by certain domestic and foreign subsidiaries. Subsequent to the Refinancing Transactions, the 2026 Notes are subject to the 2026 Supplemental Indenture.

2029 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 2026 Notes. Subsequent to the Refinancing Transactions, the 2029 Notes are subject to the 2029 Supplemental Indenture.

Revolving Facility

In April 2021, we entered into a credit agreement (the "Revolving Credit Agreement") for a $200.0 million senior secured revolving credit facility (the "Revolving Facility"). Through December 31, 2023, the Revolving Facility was amended to increase the borrowing capacity to $950.0 million. In May 2024, we entered into an amendment which increased the borrowing capacity by $50.0 million, for a total capacity of $1,000.0 million. The amendments did not impact the interest rate or term of the Revolving Facility, and no deferred costs were written off. As of December 31, 2024 and 2023, $1,000.0 million and $866.6 million was outstanding under the Revolving Facility.

The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of the Revolving Facility. The rates applicable to outstanding borrowings as of December 31, 2024 and 2023 were 8.22% and 8.29%, respectively. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium.

Concurrent with the Refinancing Transactions, we entered into an amendment with certain lenders in the Revolving Facility (the "Consenting Lenders") to extend the maturity of their commitments to October 15, 2027. The Consenting Lenders hold $900.0 million of the total revolving commitments. The applicable margin payable on revolving borrowings to the Consenting Lenders increased by 100 basis points. We are required to reduce the commitments with proceeds from certain assets sales and by certain amounts received from the settlement of our claims following the termination of our contract to provide emergency power services in Puerto Rico (Note 5). Notwithstanding these required reductions, we must reduce commitments for Consenting Lenders to $630.0 million by September 30, 2025, and as such, $270.0 million of the outstanding borrowings under the Revolving Facility have been recognized as current. The remainder of the Revolving Facility will mature in April 2026 with the potential for us to extend the maturity date once for a one-year increment.

The obligations under the Revolving Facility are guaranteed by certain of our subsidiaries, including those that own our offshore FLNG facility at Altamira ("FLNG1 Project") and Altamira Onshore Project (defined below), and are secured by substantially the same collateral securing the obligations under certain intercompany loans entered into in conjunction with the Refinancing Transactions, as well as the assets comprising the FLNG1 Project and Altamira Onshore Project. We are required to comply with the below covenants under the Revolving Facility and Letter of Credit Facility (defined below):

•Beginning with the fiscal quarter ended March 31, 2025, for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to EBITDA Ratio must be below the following: (i) 8.75 to 1.00, for the fiscal quarter

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ending March 31, 2025, (ii) 7.25 to 1.00, for the fiscal quarter ending June 30, 2025, (iii) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (iv) 6.50 to 1.00, for the fiscal quarter ending December 31, 2025, (v) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 through September 30, 2026, and (vi) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter.

•Beginning with fiscal quarter ended March 31, 2025, the Fixed Charge Coverage Ratio must be less than or equal to (i) 0.80 to 1.00, for the fiscal quarter ending March 31, 2025 and (ii) 1.00 to 1.00, for the fiscal quarter ending June 30, 2025 and each fiscal quarter thereafter.

•We are also required to maintain a minimum consolidated liquidity of (i) $50,000 as of the last day of each month, commencing as of October 31, 2024 and (ii) $100,000 as of the last day of any fiscal quarter, commencing as of December 31, 2024. We were in compliance with these covenants as of December 31, 2024.

The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Letter of Credit Facility

In July 2021, we entered into an uncommitted letter of credit and reimbursement agreement (the "Letter of Credit Agreement") with a bank for the issuance of letters of credit for an aggregate amount of up to $75.0 million (the“Letter of Credit Facility”). Through December 31, 2023, the Letter of Credit Facility was amended multiple times to increase the availability to $350.0 million. As of December 31, 2024, the Letter of Credit Facility had a limit of $315,000, and the outstanding letters of credt have an interest rate of 3.35%. We had an unutilized Letter of Credit Facility balance of $69.0 million as at December 31, 2024

Term Loan B Credit Agreement

On August 3, 2023, we entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) in an aggregate principal amount of $400.0 million. The Bridge Term Loans were initially set to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%.

On October 30, 2023, we entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to in an aggregate principal amount of $856.0 million ("Term Loan B"). Borrowings were issued at a discount, and we received proceeds of $787.5 million. The proceeds from the Term Loan B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature on the earliest of (i) October 30, 2028 if the 2026 Notes are refinanced in full prior to their maturity and (ii) July 31, 2026, if any of the 2026 Notes remain outstanding as of such date. Quarterly principal payments of approximately $2.1 million are required beginning March 2024.

The obligations under the Term Loan B are guaranteed by certain of our subsidiaries, including those that own our FLNG1 Project and Altamira Onshore Project (defined below). The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2026 Notes, the Revolving Facility, and, in addition, is secured by assets compromising our FLNG1 Project.

The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. We may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 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, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, we will be required to prepay the Term Loan B with our Excess Cash Flow (as defined in the Term Loan B Agreement).

The Term Loan B 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 Agreement.

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Term Loan A Credit Agreement

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 must be used to pay costs of the construction and development of our onshore FLNG project in Altamira (the “Altamira Onshore Project”). During the year ended December 31, 2024, we drew $350.0 million on the Term Loan A. 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.

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 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 the maturity date. In the event that our existing 2026 Notes are not refinanced or repaid at least 60 days prior to maturity, 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 plus 2.75%. The interest rate on the Term Loan A will increase by 0.25% every 180 days beginning on June 30, 2025.

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 consistent with those under the Revolving Facility, including Debt to EBITDA Ratio and minimum consolidated liquidity.

Short-term Borrowings

We may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2024, we had $179.9 million due under these arrangements.

Vessel Financing Obligation

In connection with of the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to us at the time of closing were classified as finance leases. Additionally, our charter of certain other vessels will commence only upon the expiration of the vessel's existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, we accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation for consideration received.

We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we recognize revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation;

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at inception of the arrangement, the effective interest rate on this financing obligation was approximately 15.9% and includes the cash flows that Energos receives from these third-party charters. Charter payments due in 2025 include $57.8 million that will be treated as a payment of principal, and this amount is included within the current portion of long-term debt.

Tugboat Financing

In December 2023, we sold and leased back four tugboat vessels for 15 years receiving proceeds of $46.7 million. ("Tugboat Financing"). The leasebacks of the tugboat vessels were classified as finance leases, and as such, we accounted for the Tugboat Financing as a failed sale-leaseback and has recorded a financing obligation for consideration received. The effective interest rate on this financing obligation is approximately 16.92%.

PortoCem Financings

As part of the PortoCem Acquisition, we assumed a term loan in the aggregate principal amount of R$141,445 million ($28.1 million based on the exchange rate 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 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 borrowed R$1.5 billion, and this funding was used to repay the PortoCem Credit Note and to begin the development and construction of a power plant to deliver under the capacity reserve contracts acquired in the PortoCem Acquisition. The PortoCem Bridge Loan bore interest at the one-day interbank deposit futures rate in Brazil plus 4.25%, and no principal payments were required until maturity in October 2025.

In November 2024, PortoCem issued R$4.5 billion ($726.8 million based on exchange rates in effect at December 31, 2024) of debentures to BNDES ("PortoCem Debentures"). Borrowings bear interest at 9.15%. No principal or interest payments are due until September 2027; at that point, PortoCem will begin to make semi-annual payments until maturity in September 2040. Proceeds received were utilized to repay the PortoCem Bridge Loan, and the remaining proceeds are restricted to fund the construction of the PortoCem Power Plant.

The PortoCem Debentures contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The PortoCem Debentures do not contain any restrictive financial covenants.

Barcarena Financings

In October 2023, certain of our Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of our power plant located in Pará, Brazil (the "Barcarena Power Plant"). The parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures") and issued $180 million of the Barcarena Debentures prior to December 31, 2023. The remaining series may be issued upon the achievement of certain conditions precedent. Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12.0%, increasing 1.25% each year after the third anniversary of issuance. We are able to prepay the Barcarena Debentures, subject to certain make whole penalties, and we are required to utilize certain excess cash flows from our Brazilian operations to prepay principal.

The Barcarena Debentures are convertible into shares of one of our indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.

The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own the Barcarena Facility and the Santa Catarina Facility. NFE has also provided a parent company guarantee that will be released once the Barcarena Facility commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are

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required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.

The owner of the 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"). We borrowed $344.7 million under the BNDES Credit Agreement in 2024. 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 PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.

South Power 2029 Bonds

In January 2022, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into an agreement for the issuance of up to $285.0 million secured bonds (“South Power 2029 Bonds”). The South Power 2029 Bonds are secured by, amongst other things, our combined heat and power plant in Clarendon, Jamaica (“CHP Plant”), and NFE has provided a guarantee of the obligations under the South Power 2029 Bonds. As of both December 31, 2024 and 2023, South Power had $221.8 million of South Power 2029 Bonds issued and outstanding.

The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.

South Power is required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provide for customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2024 and 2023.

Turbine Financing

In May 2024, we executed a loan agreement with a lender to borrow $148.5 million under a promissory note secured by certain turbines owned by a wholly-owned subsidiary of ours (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 recorded in Other non-current assets, net

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 NFE's green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the year ended December 31, 2023, $62.9 million was funded under the EB-5 Loan Agreement, and the remaining availability of $37.1 million was funded during the year ended December 31, 2024.

The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants.

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Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. We evaluate our estimates and related assumptions regularly, and we believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.

Impairment of long-lived assets

We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract, or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.

Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.

Geopolitical and other macroeconomic events can substantially impact natural gas and LNG markets, leading to volatility in market pricing. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a contractual spread. Based on the long-term nature of our supply and customer contracts, the nature of the pricing in these contracts and the market value of our underlying assets, changes in the price of natural gas or LNG do not indicate that a recoverability assessment of our assets is necessary. Further, LNG production from our own FLNG facilities will further mitigate our exposure to variability in LNG and natural gas prices.

When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. We develop the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.

Recent Accounting Standards

For descriptions of recently issued accounting standards, refer to “Note 3. Adoption of new and revised standards” of our notes to consolidated financial statements included in this Annual Report.

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

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors.

You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The comparison of the years ended December 31, 2022 and 2021 can be found in our Annual Report on Form 10-K for the year ended December 31, 2022 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.

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

Overview

We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable, and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in this Annual Report, “Items 1 and 2: 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. Upon the completion of commissioning in 2024, we expect to begin to source a portion of our LNG from our modular liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." 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. The Company’s investment in Energos (defined below) is also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.

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Our Current Operations – Terminals and Infrastructure

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, 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 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 from 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

Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico.

In the first and second quarters of 2023, we entered into agreements with Weston Solutions, Inc. ("Weston") 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 and ADO. Weston has been 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 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. We receive an annual management fee and are eligible for performance-based incentive fees, beginning after the service period under the contract commenced on July 1, 2023.

La Paz Facility

In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power. We placed the La Paz Power Plant into service in the third quarter of 2023.

In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. We executed the final long-form gas sales agreement in the second quarter of 2023, which is subject to certain conditions precedent including the execution of the final agreement to sell the La Paz Power Plant.

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Miami Facility

Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu from LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.

Our LNG Supply and Cargo Sales

NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts expected to commence in 2027; 3) our Miami Facility; and 4) 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. 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 commence production from our first Fast LNG facility upon the completion of commissioning in 2024. We plan to expand that capacity when additional Fast LNG units come online over the next two years.

Natural gas and LNG markets have experienced unprecedented price 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 have 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.

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 have chartered 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.

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 11 vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. 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 Sheets 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; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos.

Our Development Projects

Our projects currently under development include our development of a series of modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); our LNG terminal (“Ireland Facility”) and power plant in Ireland; and our first green hydrogen project ("ZeroPark I"). We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance

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that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.

The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.

We describe each of our current development projects below.

Fast LNG

We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. Our initial “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. As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application.

Our initial Fast LNG units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore 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 plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.

Altamira

In the first quarter of 2023, we executed an agreement, which includes conditions to effectiveness that have not been satisfied, 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 will utilize 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.

We have also entered into a non-binding MOU with CFE to develop and operate an onshore liquefied natural gas terminal with up to four 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. 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. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks.

Louisiana

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. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility which remain subject to review and approval as described under “Risk Factors—Risks Related to Our Business—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.” If constructed, the facility would be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.

Lakach

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We have been in discussions with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. Our initial agreements were terminated in the fourth quarter of 2023, however, NFE continues to be in active discussions with Pemex to develop or monetize an offshore project.

Puerto Sandino Facility

We are developing an offshore liquefied natural gas receiving and storage facility off the coast of Puerto Sandino, Nicaragua, as well as an onshore regasification facility. 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 partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.

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. 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 expect to commence operations, including delivery to the Alunorte Alumina Refinery in the first half of 2024.

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 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.

In the fourth quarter of 2023, we entered into an agreement to acquire a 1.6GW PPA in exchange for newly issued 5% NFE redeemable Series A Convertible Preferred Stock, the closing of which remains subject to customary closing conditions, including regulatory approval for the transfer of the PPA. NFE has applied to transfer the 1.6 GW PPA to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build a power plant to supply the PPA using gas from the Barcarena Facility. We expect to begin delivering electricity under the acquired PPA in July 2026.

We have financed the development of the Barcarena Power Plant pursuant to a financing agreement. For information on this financing agreement, see “—Long-Term Debt and Preferred Stock” in this Annual Report.

Santa Catarina Facility

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 are developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in 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 expect to complete our Santa Catarina Facility and commence operations in the first half of 2024.

Ireland Facility

We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. 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 are challenging this decision. 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.

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ZeroParks

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. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies.

Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the western hemisphere and numerous petrochemical manufacturers, many of which require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I and expect to commence operations on the first phase in the first half of 2025. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect our Beaumont Facility to be the largest green hydrogen plant in the United States.

Recent Developments

On February 14, 2024, we completed a transaction to sell substantially all of our stake in Energos, receiving proceeds of approximately $136.4 million. As a result of the transaction, we recognized an other than temporary impairment of our investment in Energos of $5.3 million for the year ended December 31, 2023, and this loss was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive Income.

On February 28, 2024, we entered into a commitment letter for the Company to receive $700 million in financing secured by our onshore FLNG project in Altamira, Mexico as well as the collateral securing the 2025 Notes and the 2026 Notes. The commitment letter is subject to the finalization of a credit agreement and customary closing conditions. The proceeds will be used to complete our onshore FLNG project in Altamira.

Other Matters

On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue.

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 that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 99% of our

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LNG volumes from third parties for the year ended December 31, 2023. 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. We expect to deploy our first Fast LNG unit upon the completion of commissioning in 2024.

•Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2023 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We have placed our La Paz Facility in service in 2021, and in the third quarter of 2023, we placed the La Paz Power Plant into service. We have executed agreements to extend and amend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur, and as such, our revenue and results of operations have begun to be impacted by our operations in Mexico. We are also continuing to develop our Puerto Sandino Facility, Barcarena Facility, Santa Catarina 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 from the Palo Seco Power Plant as part of the grid stabilization project in the second quarter of 2023. At the end of September 2023, we placed additional power generation assets in service at the San Juan Power Plant. We expect that our power generation assets at both the Palo Seco Power Plant and at the San Juan Power Plant will operate at full capacity, and we expect that our revenue and results of operations will benefit from significant gas consumption required to operate these assets.

•Our historical financial results include the results from our investments in the common units of Hilli LLC and CELSEPAR. 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"). In the fourth quarter of 2022, we sold our interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), the indirect owner of the Sergipe Power Plant in Brazil. As a result of these transactions, we no longer have any ownership interest in either the Hilli or the Sergipe Power Plant, and their results will no longer be included in NFE's results of operations.

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Results of Operations – Three Months Ended December 31, 2023 compared to Three Months Ended September 30, 2023 and Year Ended December 31, 2023 compared to Year Ended December 31, 2022

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. 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. 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.

Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. 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 December 31, 2023 and September 30, 2023, and for the year ended December 31, 2023 and December 31, 2022:

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(1)Prior to the completion of the sale of our ownership interest in CELSEPAR, Terminals and Infrastructure included our effective share of revenues, expenses and operating margin attributable to our 50% ownership of CELSEPAR. Terminals and Infrastructure does not include the unrealized mark-to-market gains on derivative instruments of $1.5 million and $0.4 million for the three months ended December 31, 2023 and September 30, 2023, respectively. The segment measure also excludes losses and gains of $106.4 million and $106.1 million for the years ended December 31, 2023 and 2022, respectively, reported in Cost of sales.

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

(3)Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of CELSEPAR and Hilli Common Units in our segment measure prior to the disposition of these investments, the exclusion of the unrealized mark-to-market gain or loss on derivative instruments and the exclusion of non-capitalizable contract acquisition costs.

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

(5)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 as defined under GAAP.

Terminals and Infrastructure Segment

Total revenue

Total revenue for the Terminals and Infrastructure Segment increased by $247.2 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. The increase was primarily driven by additional volumes delivered in Puerto Rico, and increases to the Henry Hub index that forms a portion of the pricing to invoice most of our downstream customers in this segment.

•Volumes delivered to downstream terminal customers increased from 20.1 TBtus in the third quarter of 2023 to 22.2 TBtu in the fourth quarter of 2023. We continue to support the grid stabilization project in Puerto Rico, and we recognized a full quarter of operations for our San Juan Power Plant during the fourth quarter; we completed the commissioning of these additional power assets at the San Juan Power Plant in September 2023. We also realize higher margins for volumes delivered at the temporary power plants at Palo Seco and San Juan, and our segment operating margin in the fourth quarter benefited from delivering additional volumes to these projects.

•The average Henry Hub index pricing used to invoice our downstream customers increased by 13% for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023.

Total revenue for the Terminals and Infrastructure Segment decreased by $27.5 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The decrease was primarily driven by lower LNG cargo sales, no pro rata share of revenue from our former investment in CELSEPAR and a reduction in the Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment. The decrease in revenue was partially offset by increased revenue from sales to downstream terminal customers.

The decrease in revenue in the year ended December 31, 2023 when compared to the year ended December 31, 2022 was primarily attributable to the following:

•LNG cargo sales to third parties decreased by $557.4 million for the year ended December 31, 2023, decreasing from $1,175.9 million for the year ended December 31, 2022 to $618.5 million for the year ended December 31,

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2023. In the second half of 2023, we utilized all LNG purchased under our long-term supply contracts for sales to our downstream terminal customers.

•After the completion of the sale of our investment in CELSEPAR in the fourth quarter of 2022, we no longer recognize revenue from this investment in our segment measure. Our share of revenue from CELSEPAR was $148.3 million for the year ended December 31, 2022, which was primarily comprised of fixed capacity payments received under related PPAs.

•The average Henry Hub index pricing used to invoice our downstream customers decreased by 59% for the year ended December 31, 2023 as compared to the year ended December 31, 2022.

Such decrease was offset by increases to revenue in the year ended December 31, 2023 when compared to the year ended December 31, 2022, due to the following:

•Volumes delivered to downstream customers were 68.3 TBtu for the year ended December 31, 2023 as compared to 39.5 TBtu for the year ended December 31, 2022, and these increased volumes were primarily attributable to our operations in Puerto Rico, Jamaica and Mexico.

•In the prior year, maintenance activities significantly lowered consumption at our facilities; there was no significant maintenance downtime during 2023. The maintenance downtime in the prior year was across our facilities, including downtime at our CHP Plant for unplanned maintenance, downtime at our Montego Bay Facility due to a reconfiguration of our assets required by the Port of Montego Bay and maintenance at PREPA's San Juan Power Plant. Volumes delivered across from these facilities increased by 13.5 TBtu as compared to the year ended December 31, 2022.

•In May 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets at the Palo Seco Power Plant. In September 2023, we finished commissioning additional power generation assets at the San Juan Power Plant. We have delivered 13.3 TBtu at a higher margin at these power plants during the year ended December 31, 2023.

Cost of sales

Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide operations and maintenance services to PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue.

Cost of sales increased $51.3 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023.

•Cost of LNG purchased from third parties for sale to our downstream customers increased by $25.7 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. The increase was primarily attributable to a 10% increase in volumes delivered compared to the three months ended September 30, 2023. The weighted-average cost of LNG purchased from third parties for sale to our customers increased from $6.78 per MMBtu for the three months ended September 30, 2023 to $7.08 per MMBtu for the three months ended December 31, 2023

•We also incurred additional costs of $19.6 million to make reimbursable improvements to our assets that are utilized as part of the Puerto Rican grid stabilization project. The reimbursement of these costs has been recognized as Other revenue.

Cost of sales decreased by $377.5 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022.

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•We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $310.3 million during the year ended December 31, 2023.

•During the year ended December 31, 2023, realized gains of $139.1 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. For segment performance measures, unrealized mark to market gains and losses are excluded until settled.

•Cost of sales for the year ended December 31, 2022 included $28.6 million of our share of cost of sales from our investment in CELSEPAR, which was primarily comprised of LNG costs to fuel a power plant owned by CELSEPAR.

•We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $48.0 million during the year ended December 31, 2023 due to increased volumes delivered; we delivered 74% more volumes to our downstream terminal customers in the current period as compared to the year ended December 31, 2022. While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was substantially lower, decreasing to $7.23 per MMBtu for the year ended December 31, 2023 from $10.84 per MMBtu for the year ended December 31, 2022.

•We recognized additional payroll and other operating costs of $35.6 million to provide services under Genera's operations and maintenance contract.

The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 2023 and December 31, 2022 was $7.33 per MMBtu and $10.42 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 increase by $17.5 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023, which was primarily related to additional vessel costs incurred in our terminal operations as costs related to the Winter and Princess are recognized in our terminal costs following the conclusion of these vessels long-term charters.

Operations and maintenance increased by $36.8 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022, which was attributable to the following activity:

•In 2023, we leased turbines to generate power at the Palo Seco Power Plant as part of the grid stabilization project in Puerto Rico. We also undertook activities to ensure that we have LNG supply available for our expanded Puerto

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Rican operations, including leasing berth space to place a storage vessel to service Puerto Rico, increasing operations and maintenance costs when compared to the prior year.

•These increases were partially offset by the exclusion of our share of Operations and maintenance from the investment in CELSEPAR; after the sale of our investment in CELSEPAR in the fourth quarter of 2022, we do not include these costs during the year ended December 31, 2023.

Ships Segment

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. Prior to the completion of the Energos Formation Transaction, we also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of the Nanook. We included the interest income earned under sales-type leases as revenue as amounts earned under chartering and operating service agreements represented our ongoing ordinary business operations.

On March 15, 2023, we completed the "Hilli Exchange. In the fourth quarter of 2022, we recognized a loss on the investment in Hilli LLC of $118.6 million; this loss was recognized in Loss from equity method investments in the Consolidated Statements of Operations and Comprehensive Income. Upon completion of the Hilli Exchange during the first quarter of 2023, we recognized an additional loss on disposal of $37.4 million, which was included in Other expense (income), net. As a result of the Hilli Exchange we no longer have an ownership interest in the Hilli. NFE shares received from GLNG were cancelled upon the closing of the Hilli Exchange.

As of December 31, 2023, three FSRUs and one LNG carrier were leased to customers under long-term arrangements. In July 2023, we sold the vessel Spirit for a total consideration of $15.8 million resulting in a gain of $7.8 million. The gain on sale is included in Gain on sale of assets, net in the Consolidated Statements of Operations and Comprehensive Income. In December 2023, we entered into an agreement to sell the vessel Mazo, for $22.4 million; the sale closed in the first quarter of 2024, and as such, the vessel has been classified as held for sale as of December 31, 2023. In conjunction with the classification as held for sale, the Company recognized an impairment of $10.9 million within Asset impairment expense in the Consolidated Statements of Operations and Comprehensive Income.

Total revenue

Total revenue for the Ships segment decreased $3.3 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of vessels included in the transaction (except the Nanook), and as such, we continue to recognize revenue from the charter of these vessels to third parties. The decrease in revenue was primarily driven by end of third-party charter of Winter and Princess during the fourth quarter of 2023.

Total revenue for the Ships segment decreased by $151.0 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The decrease in revenue was primarily the result of the sale of the Nanook as part of the Energos Formation Transaction; we no longer recognize revenue related to the Nanook in 2023. After the Hilli

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Exchange at the end of the first quarter of 2023, we no longer recognize revenue from the Hilli, further decreasing revenue in the Ships segment. Additionally the charters for two vessels concluded in the first quarter of 2023 and the charters for another two vessels concluded in the fourth quarter of 2023, lowering vessel revenue for the year ended December 31, 2023. We plan to utilize these vessels in our operations following conversion and other upgrades starting in 2024.

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. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.

Vessel operating expenses decreased by $2.5 million for the three months ended December 31, 2023, compared to the three months ended September 30, 2023 primarily due to end of third-party charter of Winter and Princess during the fourth quarter of 2023.

Vessel operating expenses decreased by $39.2 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022. The decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the Hilli Exchange at the end of the first quarter of 2023. During 2023, the Company started using four vessels that were in the Ships segment in 2022 for its terminal operations, resulting in lower vessel operating costs. The costs also decreased as a result of the sale of the Nanook as part of the Energos Formation Transaction; we recognized vessel operating expenses related to the Nanook during 2022 and no longer recognize vessel operating expenses related to the Nanook in 2023.

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Other operating results

Selling, general and administrative

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

Selling, general and administrative for the three months ended December 31, 2023 decreased by $1.1 million as compared to the three months ended September 30, 2023.

Selling, general and administrative decreased by $30.9 million for the year ended December 31, 2023, compared to the year ended December 31, 2022. The decreases were primarily due to lower share-based compensation expense, as we did not recognize any cost related to employee performance share units in 2023, as well as lower professional fees and screening costs.

Transaction and integration costs

For the three months ended December 31, 2023, we did not incur significant transaction and integration costs as compared to the prior quarter.

For the year ended December 31, 2023, we incurred $6.9 million for transaction and integration costs, as compared to $21.8 million for the year ended December 31, 2022. In the prior year, we incurred transaction and integration costs primarily associated with the sale of our investment in CELSEPAR and the Energos Formation Transaction, and there were no such similar significant transactions during the year-ended December 31, 2023.

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Depreciation and amortization

Depreciation and amortization increased by $13.5 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. In September 2023, we placed assets at the San Juan Power Plant in service as part of the grid stabilization project in Puerto Rico. Additionally, in September 2023 we placed our La Paz Power Plant into partial service, and we recognized a full quarter of depreciation in the fourth quarter of 2023.

Depreciation and amortization increased by $44.7 million for the year ended December 31, 2023 as compared to the year ended December 31, 2022, primarily the result of assets including turbines placed into service as part of the grid stabilization project at the Palo Seco Power Plant and San Juan Power Plant during 2023.

Asset impairment expense

As a result of our acquisition of Hygo Energy Transition Limited in 2021, we recognized long-lived assets associated with the expansion of the Sergipe Power Plant. During the year ended December 31, 2022, we recognized asset impairment expense of $50.7 million, as the fair value of these assets was less than the carrying value, and the asset group was held for sale. In December 2023, we entered into an agreement to sell the vessel Mazo, for $22.4 million; the sale closed in the first quarter of 2024. The vessel has been classified as held for sale as of December 31, 2023, and in conjunction with the classification as held for sale, the Company recognized an impairment of $10.9 million.

Gain on sale of assets, net

In July 2023, we sold the vessel Golar Spirit for a total consideration of $15.8 million resulting in a gain of $7.8 million. In addition, during the fourth quarter of 2023, we completed the sale of 100% of shares of Pecém and Muricy for a total gain of $21.5 million.

Interest expense

Interest expense increased by $12.1 million for the three months ended December 31, 2023 as compared to the three months ended September 30, 2023. The increase was primarily due to the higher borrowing costs on our Term Loan B (defined below) issued in October 2023 and Barcarena Debentures (defined below) issued in November 2023.

Interest expense increased by $41.0 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022. The increase was primarily due to an increase in total principal outstanding, including obligations incurred as a result of the Energos Formation Transaction, under which we incur higher borrowing costs. The total principal balance on outstanding facilities was $6.9 billion as of December 31, 2023 as compared to total outstanding debt of $4.6 billion as of December 31, 2022.

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Other expense (income), net

Other income, net and other expense, net was $13.6 million and $5.6 million for the three months ended December 31, 2023 and September 30, 2023, respectively. Other expense, net and Other income, net was $10.4 million and $48.0 million for the year ended December 31, 2023 and December 31, 2022, respectively.

Other income, net recognized in the three months ended December 31, 2023 was primarily comprised of interest income and foreign currency remeasurement gains.

Other expense, net recognized in the year ended December 31, 2023 was primarily comprised of loss on disposal of our equity method investment in Hilli LLC in the Hilli Exchange during the first quarter of 2023. The losses were partially offset by the interest income and gains on certain derivative transactions.

Loss on extinguishment of debt

Loss on extinguishment of debt was $15.0 million for the year ended December 31, 2022 as a result of the extinguishment of the certain debt facilities and sale leaseback financing arrangements with VIEs with proceeds from the Energos Formation Transaction. We did not have any such transactions during the year ended December 31, 2023.

Income (loss) from equity method investments

We recognized a loss from our investment in Energos of $2.8 million for the three months ended December 31, 2023 as compared to income of $0.5 million and for the three months ended September 30, 2023. We have entered into a Unit Purchase Agreement to sell substantially all of our stake in the Energos, and as a result of the transaction, we recognized an other than temporary impairment ("OTTI") totaling $5.3 million.

We recognized income from our equity method investments of $10.0 million for the year ended December 31, 2023. For the year ended December 31, 2022, we recognized losses from our equity method investments of $472.2 million. The losses were primarily driven by an other than temporary impairment of the investments in CELSEPAR and Hilli LLC of $487.8 million recognized in connection with the announced sale of these investments, partially offset by income attributable to our investments in Energos.

Tax provision

We recognized a tax provision of $115.5 million for the year ended December 31, 2023 compared to a tax benefit of $123.4 million year ended December 31, 2022. For the year ended December 31, 2023, the tax provision was primarily driven by domestic income tax expense from significant income generated by our foreign operations on our domestic tax expense; this additional U.S. tax expense was partially offset by the tax benefit from the utilization of foreign tax credits.

For the year ended December 31, 2022, we reflected an excess benefit from stock compensation of $24.4 million. Prior to the completion of the sale of our investment in CELSEPAR, our equity method investment in CELSEPAR was directly held by a subsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil, resulting in a discrete benefit of $76.5 million recognized in the first quarter of 2022. Additionally, in the second and third quarters of 2022, we recognized an impairment on the value of this investment, resulting in a further discrete benefit of $122.4 million.

Liquidity and Capital Resources

We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. Our significant capital projects, primarily our first FLNG unit, are nearing completion, and as with many capital projects, a significant portion of the overall capital spending becomes due near the completion of the project.

We expect the current working capital position to improve based on the following: (1) expected cash flows generated from the temporary power project and from sales of our own LNG generated by our first deployed Fast LNG unit; (2) 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 the remaining cost of our onshore FLNG project at Altamira; (3) our credit

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agreements allow for proceeds from the sale of assets to be reinvested in our business, and we have significant non-core assets that could be used to fund our developments; and (4) our relationships with certain significant 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.

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. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions. 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, 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 remaining committed capital expenditures is approximately $1,365 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 Facility, Barcarena Power Plant, Santa Catarina Facility and Beaumont Facility. We have secured financing commitments to continue to develop our onshore Altamira project and the Barcarena Power Plant, which represents approximately $1,072 million of our upcoming committed capital expenditures.

We expect fully completed Fast LNG units to cost between $1.0 billion and $1.6 billion per unit. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to construct the Fast LNG units allow us to closely control the timing of our spending and construction schedules so that we can complete each project in time frames to meet our business needs. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.

As of December 31, 2023, 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. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106.1 million, has been capitalized, and to date, we have repurposed approximately $16.8 million of engineering and equipment to our Fast LNG project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities.

On December 12, 2022, our Board of Directors approved an update to our dividend policy. In connection with the dividend policy update, the Board declared a dividend of $626.3 million, representing $3.00 per Class A share, which was paid during the first quarter of 2023. Additionally, we declared and paid quarterly dividends totaling $81,976 during the year ended December 31, 2023, representing $0.10 per Class A share. Our future dividend policy is within the discretion of our Board of Directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our Board of Directors may deem relevant. In the third quarter of 2023, our Board of Directors reinstated a dividend policy of targeting a quarterly dividend of $0.10 per share.

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Contractual Obligations

We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2023:

Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2023.

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. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. 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.

We entered into the BNDES Credit Agreement and an agreement to issue the Barcarena Debentures (defined below). Proceeds from these new credit arrangements have been or will be used to refinance the Barcarena Term Loan on a long term basis, and as such, these principal balances have been shown as non-current on the Consolidated Balance Sheets as of December 31, 2023.

Purchase obligations

We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. 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 December 31, 2023.

We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and Beaumont Facility. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.

Lease obligations

Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, gas turbines and a land lease.

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Cash Flows

The following table summarizes the changes to our cash flows for the year ended December 31, 2023 and 2022, respectively:

Cash provided by operating activities

Our cash flow provided by operating activities was $824.8 million for the year ended December 31, 2023, which increased by $469.6 million from cash provided by operating activities of $355.1 million for the year ended December 31, 2022. Our net income for the year ended December 31, 2023, when adjusted for non-cash items, increased by $175.5 million from the year ended December 31, 2022. The increase in cash provided by operating activities for the year ended December 31, 2023 was also driven by changes in working capital, including improved collection of receivables and the settlement of a significant commodity derivative, as well as significant cash receipts under our temporary power agreements that are required to be deferred as contract liabilities.

Cash used in investing activities

Our cash flow used in investing activities was $2,904.1 million for the year ended December 31, 2023, which increased by $2,821.4 million from cash used in investing activities of $82.7 million for the year ended December 31, 2022. Cash outflows from investing activities during the year ended December 31, 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, proceeds received from the sale of Pecém and Muricy, as well as proceeds received from the sale of the Spirit and a portion of our investment in equity securities.

Cash outflows for investing activities during the year ended December 31, 2022 were used for continued development of our Fast LNG project, Santa Catarina Facility, and Barcarena Facility. Cash outflows were offset by proceeds of $593.0 million from the sale of the finance lease of the Nanook and $500.1 million from selling our investment in CELSEPAR.

Cash provided by financing activities

Our cash flow provided by financing activities was $1,529.0 million for the year ended December 31, 2023, which increased by $1,207.0 million from cash provided by financing activities of $322.0 million for the year ended December 31, 2022. On December 12, 2022, the Company's Board of Directors approved an update to its dividend policy and declared a dividend of $626,310, representing $3.00 per Class A share, which was paid in January 2023. We have borrowed under our new Term Loan B Agreement, expanded Revolving Facility, Bridge Term Loans, Equipment Notes, Barcarena Debentures, EB-5 Loan, Tugboat Financing, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $3.0 billion. 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 $686.5 million, primarily the repayment of the Bridge Term Loans and short-term borrowings under repurchase arrangements.

Cash provided by financing activities during the year ended December 31, 2022 was due to proceeds from issuance of debt of $2.0 billion, offset by repayments of debt of $1.5 billion, payment of dividends of $99.1 million and payments related to tax withholdings for share-based compensation of $72.6 million.

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Long-Term Debt and Preferred Stock

2025 Notes

In September 2020, we issued $1,000.0 million of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments are due until maturity on September 15, 2025. We may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.

In December 2020, we issued $250.0 million of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein).

2026 Notes

In April 2021, we issued $1,500.0 million of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of each year; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

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

Vessel Financing Obligation

In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to us at the time of closing were classified as finance leases. Additionally, our charter of certain other vessels will commence only upon the expiration of the vessel's existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, we accounted for the Energos Formation Transaction as a failed sale-leaseback and have recorded a financing obligation for consideration received.

We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we recognize revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation; the effective interest rate on this financing obligation of approximately 15.9% includes the cash flows that Energos receives from these third-party charters.

Revolving Facility

In April 2021, we entered into a credit agreement (the "Revolving Credit Agreement") with a bank for $200.0 million senior secured revolving credit facility (the "Revolving Facility"). The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of the Revolving Facility. The Revolving Facility will mature in 2026 if the 2025 Notes are refinanced prior to maturity, with the potential for us to extend the maturity date of the Revolving Facility once for a one-year increment; if not, the Revolving Facility becomes due approximately 60 days prior to the maturity of the 2025 Notes. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium.

In 2022, the Revolving Credit Agreement was amended twice to increase the borrowing capacity by a total of $240.0 million, and in the year ended December 31, 2023, we entered into additional amendments which increased the borrowing capacity by $510.0 million, for a total capacity of $950,000.0 million. The amendments did not impact the interest rate or

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term of the Revolving Facility, and no deferred costs were written off. During the year ended December 31, 2023, we drew $866.6 million from the Revolving Facility, which is outstanding as of December 31, 2023.

The obligations under the Revolving Facility are guaranteed by certain of our subsidiaries, including those that own the Company's first Fast LNG asset, and are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes. Additionally the Revolving Facility is secured by assets comprising our first Fast LNG project in Altamira, Mexico. We are required to comply with covenants under the Revolving Facility and Letter of Credit Facility (defined below), 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. We were in compliance with all covenants as of December 31, 2023.

The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Letter of Credit Facility

In July 2021, we entered into an uncommitted letter of credit and reimbursement agreement (the "Letter of Credit Agreement") with a bank for the issuance of letters of credit for an aggregate amount of up to $75 million (the “Letter of Credit Facility”). In July 2022, the Letter of Credit Facility was upsized to $250 million with the ability to increase the total limit by up to $100 million, subject to satisfaction of certain conditions. In February 2023, the Letter of Credit Facility was upsized to $325 million, and in November 2023, the Letter of Credit Facility was upsized to $350 million. The letters of credit bear interest at a rate equal to a base rate plus 2.75%.

The obligations under the Letter of Credit Facility are guaranteed by certain of our subsidiaries, including those that own the Company's first Fast LNG asset, and are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes. Additionally the Letter of Credit Facility is secured by assets comprising our first Fast LNG project in Altamira, Mexico.

The Letter of Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Term Loan B Credit Agreement

On August 3, 2023, we entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) to us in an aggregate principal amount of $400.0 million. The Bridge Term Loans were to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%.

On October 30, 2023, we entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to us in an aggregate principal amount of $856.0 million ("Term Loan B"). Borrowings were issued at a discount, and we received proceeds of $787.5 million. The proceeds from the Term Loan B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature on the earliest of (i) October 30, 2028 if the 2025 Notes and 2026 Notes are refinanced in full prior to their maturities, (ii) July 16, 2025, if any of the 2025 Notes remain outstanding as of such date, and (iii) July 31, 2026, if any of the 2026 Notes remain outstanding as of such date. Quarterly principal payments of approximately $2.1 million will be due starting March 2024.

The obligations under the Term Loan B are guaranteed by certain of our subsidiaries, including those that own our first Fast LNG project in Altamira, Mexico. The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2025 Notes and the 2026 Notes, and, in addition, is secured by assets comprising our first Fast LNG project..

The Term Loan B bears interest at a per annum rate equal to Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. We may prepay the Term Loan B at our option subject to prepayment premiums until October 2025 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, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, we will be required to prepay the Term Loan B with our Excess Cash Flow (as defined in the Term Loan B Agreement).

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The Term Loan B 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 Agreement.

South Power 2029 Bonds

In January 2022, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into an agreement for the issuance of up to $285.0 million secured bonds (“South Power 2029 Bonds”). The South Power 2029 Bonds are secured by, amongst other things, our combined heat and power plant in Clarendon, Jamaica (“CHP Plant”), and NFE has provided a guarantee of the obligations under the South Power 2029 Bonds. As of both December 31, 2023 and 2022, South Power had $221.8 million, respectively, of South Power 2029 Bonds issued and outstanding.

The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.

South Power is required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provide for customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2023 and 2022.

Barcarena Financings

In the third quarter of 2022, certain of our indirect subsidiaries entered into a financing agreement to borrow up to $200.0 million due upon maturity in February 2024 (the “Barcarena Term Loan”); proceeds were utilized to fund a portion of the construction of the Barcarena Power Plant. As of December 31, 2022, the loan was fully funded. Interest is due quarterly, and outstanding borrowings bear interest at a rate equal to the Secured Overnight Financing Rate ("SOFR") plus 4.70%.

The obligations under the Barcarena Term Loan are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and New Fortress Energy Inc. has provided a parent company guarantee. Collateral on the Barcarena Term Loan includes liens on shares of entities constructing the our Barcarena Terminal and Barcarena Power Plant, liens on equipment and machinery owned by these entities, and rights to future operating cash flows and receivables under the Barcarena Power Plant's power purchase agreements. We are required to comply with customary affirmative and negative covenants, and the Barcarena Term Loan also provides for customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2023 and 2022.

In October 2023, certain of our Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of the Barcarena Power Plant. Proceeds received will be used to repay the Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025. As we have committed financing in place to extinguish the Barcarena Term Loan as of December 31, 2023, the Barcarena Term Loan has been presented as long-term debt on the Consolidated Balance Sheets.

The parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200.0 million of convertible debentures maturing in October 2028 ("Barcarena Debentures") and issued $180 million of the Barcarena Debentures prior to December 31, 2023. Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12%, increasing 1.25% each year after the third anniversary of issuance. We are able to prepay the Barcarena Debentures, subject to customary break funding costs, and we are required to utilize certain excess cash flows from our Brazilian operations to prepay principal.

The Barcarena Debentures are convertible to shares of one of our indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.

The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own the Barcarena Terminal and Santa Catarina Terminal. NFE has also provided a parent company guarantee that will be released once the Barcarena Terminal commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are

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required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.

Additionally, the owner of the 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 R$1.8 billion under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"); no amounts were funded under the BNDES Credit Agreement as of December 31, 2023. 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.

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 PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.

Equipment Notes

In June 2023, we executed a Master Loan and Security Agreement with a lender to borrow up to $200.0 million under promissory notes secured by certain turbines acquired in the first quarter of 2023 to support our grid stabilization project in Puerto Rico (the “Equipment Notes”). During the second and third quarters of 2023, we borrowed the full capacity bearing interest at approximately 7.7%, and the principal is partially repayable in monthly installments over the 36 month term of the loan with the balance due upon maturity in July 2026.

The Equipment Notes contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Equipment Notes do not contain any restrictive financial covenants. NFE has provided a guarantee of the obligations under the Equipment Notes.

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 NFE's green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the year ended December 31, 2023, $62.9 million was funded under the EB-5 Loan Agreement.

The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants.

Short-term Borrowings

We may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2023, we had $182.3 million outstanding under these arrangements.

Tugboat Financing

In December 2023, we sold and leased back four tugboat vessels for 15 years receiving proceeds of $46.7 million. ("Tugboat Financing"). The leasebacks of the tugboat vessels were classified as finance leases, and as such, we accounted for the Tugboat Financing as a failed sale-leaseback and have recorded a financing obligation for consideration received. The effective interest rate on this financing obligation is approximately 16.92%.

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Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. We evaluate our estimates and related assumptions regularly, and we believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.

Impairment of long-lived assets

We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract, or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.

Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.

Geopolitical and other macroeconomic events can substantially impact natural gas and LNG markets, leading to volatility in market pricing. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a contractual spread. Based on the long-term nature of our supply and customer contracts, the nature of the pricing in these contracts and the market value of our underlying assets, changes in the price of natural gas or LNG do not indicate that a recoverability assessment of our assets is necessary. Further, with our own LNG production from FLNG facilities expected to commence in 2024, we plan to further mitigate our exposure to variability in LNG and natural gas prices.

When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. We develop the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.

Recent Accounting Standards

For descriptions of recently issued accounting standards, refer to “Note 3. Adoption of new and revised standards” of our notes to consolidated financial statements included in this Annual Report.

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

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The comparison of the years ended December 31, 2021 and 2020 can be found in our Annual Report on Form 10‑K for the year ended December 31, 2021 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with GAAP. This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.

Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to the completion of Mergers (defined below), New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries, and (ii) after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP and its subsidiaries.

Overview

We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable, and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in this Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Very-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. Starting in 2023, 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." 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 or spot arrangements. The Company’s investments in Hilli LLC, owner and operator of the Hilli, and Energos (defined below) are also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.

Our Current Operations – Terminals and Infrastructure

Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica

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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”), a subsidiary of Federal Electricity Commission (Comisión Federal de Electricidad), 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 61,000 MMBtu from 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 (the “Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term 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

Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico.

La Paz Facility

In July 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility is expected to supply approximately 22,300 MMBtu from LNG per day to our 100MW of power supplied by gas-fired modular power units (the “La Paz Power Plant”) following the start of operations. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu from LNG per day for up to 135MW of power.

In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE and are in the process of finalizing long-form agreements to commemorate all binding terms. The gas sales and power plant sale agreements are subject to execution of the long-form final agreements and certain conditions precedent, and we expect to execute the long-form final agreements in the first quarter of 2023. We do not expect to recognize a loss on sale upon completion of this transaction.

Miami Facility

Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu from LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.

Our LNG Supply and Cargo Sales

NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts

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expected to commence in 2026; 3) our Miami Facility; and 4) 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. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, that are expected to commence in 2026 and 2027. Finally, we plan to commence our own Fast LNG production in 2023, when our first FLNG facility is expected to begin operation, and we plan to expand that capacity when additional units come online over the next two years.

The recent geopolitical events in Europe have substantially impacted the natural gas and LNG markets with unprecedented price increases and volatility. 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 from FLNG facilities expected to commence in 2023, we plan to further mitigate our exposure to variability in LNG prices. Due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated 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.

Our Current Operations – Ships

Our Ships segment includes five FSRUs and five LNG carriers, which are leased to customers under long-term or spot arrangements and our investment in Hilli LLC, owner and operator of the Hilli. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. One LNG carrier and FSRU are currently utilized in our terminal operations, and the results of operations of these vessels are reflected in the Terminals and Infrastructure segment. In August 2022, we completed a financing transaction with an affiliate of Apollo Global Management, Inc. collateralized by our vessels. See “—Factors Impacting Comparability of Our Financial Results” for more details about this transaction; the results of operations from charters of vessels included in this transaction continue to be included in our Ships segment as well as our equity method investment in Energos (defined below).

Our Development Projects

Our projects currently under development include our development of a series of modular floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); and our LNG terminal (“Ireland Facility”) and power plant in Ireland. We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations.

The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects.

We describe each of our current development projects below.

Fast LNG

We are currently developing multiple modular floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing offshore liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefication solutions. The “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 land-based 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.

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Our initial Fast LNG units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore 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. We expect to deploy our first Fast LNG unit in 2023 and additional units in 2024.

We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.

Altamira

In the fourth quarter of 2022, we finalized short-form agreements, which include conditions to effectiveness that have not been satisfied, with the Comisión Federal de Electricidad (“CFE”) to supply natural gas to two FLNG units located off the coast of Altamira, Tamaulipas, Mexico. These arrangements are subject to finalizing long-form definitive agreements and satisfying certain conditions precedent. Each 1.4 million tons per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. We expect to deploy our first FLNG unit to Altamira in 2023.

Louisiana

In addition, we plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG.

Lakach

Also, in the fourth quarter of 2022, we finalized agreements, which include conditions to effectiveness that have not been satisfied, with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. If the agreements become effective, NFE would invest in the continued development of the Lakach field over a two-year period by completing seven offshore wells and to deploy a 1.4 MTPA Fast LNG unit to liquefy the majority of the produced natural gas. Remaining natural gas and associated condensate volumes would be utilized by Pemex in Mexico's onshore domestic market.

Puerto Sandino Facility

We are developing an offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 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 partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.

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 up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to supply gas to third-party industrial and power customers as well as the Barcarena Power Plant, a new 605MW combined cycle thermal power plant to be located in Pará, Brazil, which we own and which is supported by multiple 25-year power purchase agreements to supply electricity to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025. We substantially completed our Barcarena Facility in 2022 and expect to commence operations by the end of 2023. We expect to complete the Barcarena Power Plant and to commence operations in 2025.

We have financed the development of the Barcarena Power Plant pursuant to a financing agreement. See “—Long-Term Debt and Preferred Stock.”

Santa Catarina Facility

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The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtus per day and LNG storage capacity of up to 170,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in 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 expect to complete our Santa Catarina Facility and commence operations in 2023.

Ireland Facility

We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. We are in the process of obtaining final planning permission from An Bord Pleanála (“ABP”) in Ireland. While the specific timing for receiving the required permits is unknown, we have undertaken pre-development work that will allow us to complete the terminal in approximately 9-15 months after receiving the required permits. We currently expect to begin operations in the first half of 2024.

Recent Developments

On February 6, 2023, we announced an agreement with Golar LNG Limited (“GLNG”) for the sale of our ownership stake in the Hilli Episeyo (the “Hilli”) in exchange for the return of approximately 4.1 million NFE shares and $100.0 million in cash (the "Hilli Exchange"). Pursuant to the transaction, we will no longer have any interest in the 2.4 MTPA floating liquefaction facility Hilli. This transaction is expected to close in the first quarter of 2023 and is subject to customary closing conditions.

Recent market prices of NFE shares and the terms of the Hilli Exchange implied that the fair value of the investment may be lower than the carrying value as of December 31, 2022, which triggered an assessment of the recoverability of the carrying amount of this investment. We estimated the fair value of the investment as of December 31, 2022 and concluded that the estimated fair value was below the carrying value and that this decline was other than temporary. As a result of this recoverability assessment, we recognized an OTTI of the investment in Hilli of $118,558 for the year ended December 31, 2022; this loss was recognized in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). The gain or loss recognized upon the closing of the Hilli Exchange will be determined based upon the share price at closing.

In February 2023, the Revolving Facility (defined below) was amended to increase the facility size by $301.7 million to $741.7 million. The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed. No changes were made to the maturity date or covenants. Also, in February 2023, our uncommitted letter of credit and reimbursement agreement was upsized to $325 million; no changes to interest rates or other terms were made as part of this amendment.

Other Matters

On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021, FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC orders were affirmed by the United States Court of the Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

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Factors Impacting Comparability of Our Financial Results

Significant 2022 Transactions

We completed significant transactions in 2022 and 2021, including a significant sales and financing transaction collateralized by certain vessels as further described below, the sale of our investment in entities owning the Sergipe Power Plant (defined below) and our acquisitions of GMLP and Hygo, and these significant transactions impact the comparability of our historical financial results of operations.

Energos Formation Transaction

On August 15, 2022, the Company and an affiliate of certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc., AP Neptune Holdings Ltd. ("Purchaser"), created a joint venture and completed a sales and financing transaction resulting in cash proceeds of approximately $1.85 billion. This sales and financing transaction comprised (1) the formation of a joint venture doing business as Energos Infrastructure ("Energos"), (2) the sale for cash of eight vessels, along with these vessels' owning and operating entities to the Purchaser, (3) the contribution of acquired vessel-owning entities to Energos by the Purchaser and (4) the Company's contribution of three vessels, along with each vessel's' owning and operating entities, to Energos in exchange for equity in Energos (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, we own approximately a 20% equity interest in Energos, with the remaining interest owned by the Purchaser. We have accounted for the investment in Energos as an equity method investment.

In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for periods of up to 20 years in respect of ten of the eleven vessels, the terms of which will commence upon the expiration of each vessel's existing charter. These charters prevent the recognition of a sale of these ten vessels to Energos, and as such, proceeds associated with these ten vessels have been treated as failed sale leasebacks. These vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and we have recognized this failed sale leaseback financing as debt. Certain vessels included in the Energos Formation Transaction are currently chartered to third parties under operating leases. As we have not recognized the sale of these vessels and proceeds received under the Energos Formation Transaction are collateralized by the cash flows from these charters, revenue generated from these operating leases continues to be recognized as Vessel charter revenue; costs of operating the vessels is included in Vessel operating expenses over the terms of the third-party charters. Cash flows from these third-party charters are included as part of debt service for the sale leaseback financing debt, and we will recognize additional financing costs within Interest expense, net.

We have not entered into a charter agreement to leaseback the Nanook. The Nanook was previously accounted for as a finance lease and proceeds received have been allocated between financing of other vessels and the sale of the Nanook. After closing this transaction, we no longer recognize revenue from the sales-type lease of the Nanook to CELSE and the related operating services agreement.

Sergipe Sale

We acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) as part of the Hygo Merger (defined below); CELSEPAR owns 100% of the share capital of Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of a 1.5GW power plant in Sergipe, Brazil (the "Sergipe Power Plant"). The Sergipe Power Plant was jointly owned and operated with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., and the Company accounted for this 50% investment using the equity method.

On May 31, 2022, one of our subsidiaries and certain Ebrasil sellers as owners of CELSEPAR (the “Sergipe Sellers”), Eneva S.A., as purchaser ("Eneva") and Eletricidade do Brasil S.A. -- Ebrasil, entered into a Share Purchase Agreement pursuant to which Eneva agreed to acquire all of the outstanding shares of (a) CELSEPAR and (b) Centrais Elétricas Barra dos Coqueiros S.A. ("CEBARRA"), which owns 1.7GW of expansion rights adjacent to the Sergipe Power Plant (the “Sergipe Sale”). The Sergipe Sale was completed on October 3, 2022, and Eneva paid the Sergipe Sellers R$6.8 billion (approximately $1.3 billion using the exchange rate as of the closing date). We also entered into a foreign currency forward associated to mitigate foreign currency risk to the expected proceeds from the transaction, and this foreign currency forward settled on October 3, 2022, resulting in a gain of $20.4 million.

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Since the Sergipe Sale in October 2022, we no longer include the results of our equity method investment in CELSEPAR in our financial statements. The results of operations of the Sergipe Power Plant were included in our Terminal and Infrastructure segment results, contributing segment operation margin of $95.6 million for the year ended December 31, 2022. Finally, we have recognized an other than temporary impairment on our investment in CELSEPAR of $369.2 million and an impairment loss on the assets held by CEBARRA of $50.7 million; as the Sergipe Sale closed in 2022, there will be no further impairment loss on this investment in future periods.

Hygo Merger and GMLP Merger

On April 15, 2021, we completed the acquisitions of Hygo (the "Hygo Merger") and GMLP (the "GMLP Merger," and collectively with the Hygo Merger, the “Mergers”) As a result of the Mergers, we acquired a 50% interest in the Sergipe Power Plant and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), the Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. We also acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli. The results of operations of the vessels acquired are included in our results of operations for the period after the acquisition date in 2021 and for a full year in 2022; the Nanook is only included in our results of operations in 2022 for the period prior to the Energos Formation Transaction.

Comparability to future periods

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 that 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 year ended December 31, 2022. We anticipate the deployment of Fast LNG facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers.

•Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2022 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We have placed a portion of our La Paz Facility into service, and our revenue and results of operations have begun to be impacted by operations in Mexico. We have executed short-form agreements to extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and are in the process of finalizing long-form agreements to commemorate all binding terms. We are also continuing to develop our Puerto Sandino Facility, and our current results do not include revenue and operating results from this project. Our current results also exclude other developments, including the Barcarena Facility, Santa Catarina Facility and Ireland Facility.

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Results of Operations – Three Months Ended December 31, 2022 compared to Three Months Ended September 30, 2022 and Year Ended December 31, 2022 compared to Year Ended December 31, 2021

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. 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. 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.

Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income/(loss) from operations, net income/(loss), cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions to facilitate measuring and achieving optimal financial performance of our current operations overall. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. 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 December 31, 2022 and September 30, 2022, and for the year ended December 31, 2022 and December 31, 2021:

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