What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-05-09 compared with 2023-11-09 · 281 added, 355 removed, 268 unchanged (70% of the section changed)

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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, 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 investment in Energos (defined below) is also included in the Ships segment.

Upon the completion of commissioning in 2024, 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.

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

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

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

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.

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.

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

The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant 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.

Weston has been contracted by the U.S.

The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant, industrial end-user customers in Puerto Rico, and after being awarded a new gas sale agreement in the first quarter of 2024, PREPA's gas-fired power plants throughout the island of Puerto Rico.

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

Our customer was contracted by the U.S.

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

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

In 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 will receive an annual management fee and be eligible for performance-based incentive fees, beginning after the service period under the contract commenced on July 1, 2023.

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

We believe that there are remedies available under our customer contract, and we are currently in pursuit of these remedies.

As the result of this process is uncertain, any transaction price associated with closing this contract has been fully constrained.

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

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

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

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

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

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 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 of LNG per day to our 100MW gas-fired modular power units (the “La Paz Power Plant”), which we placed into service in the third quarter of 2023.

Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu of LNG per day for up to 135MW of power.

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.

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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.

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

Our LNG Supply and Cargo Sales

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

Finally, we plan to commence production from our own Fast LNG facilities upon the completion of commissioning .

We plan to expand that capacity when additional Fast LNG 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.

Finally, we plan to commence production from our own Fast LNG facilities upon the completion of commissioning in 2024 .

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

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

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 expected to commence in the fourth quarter of 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.

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 or spot arrangements.

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

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

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

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 vessel to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos.

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.

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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.

(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 floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies;

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”);

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

and our LNG terminal (“Ireland Facility”) and power plant in Ireland.

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 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.

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.

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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.

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 site-built alternatives.

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

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

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.

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

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

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

Our first Fast LNG unit is being 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.

In the first quarter of 2023, we executed an agreement, which include 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.

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

We describe our currently planned projects below.

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

The 1.4 million ton per annum (“MTPA”) FLNG unit 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 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.

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.

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

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

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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.

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 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.

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.

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 facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua.

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.

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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 630MW combined cycle thermal power plant to be located in Pará, Brazil, which we own.

The Barcarena Power Plant 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 in the first quarter of 2024.

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.

For information on this financing agreement, see “—Long-Term Debt and Preferred Stock” in our Annual Report.

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 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 power power purchase agreement in Brazil.

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

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

Santa Catarina Facility

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.

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 connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A.

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

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

We expect to complete our Santa Catarina Facility and commence operations in the first quarter of 2024.

We expect to complete our Santa Catarina Facility and commence operations in the first half of 2024.

Ireland Facility

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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.

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.

Recent Developments

Barcarena Financings

In October 2023, certain the Company's Brazilian subsidiaries entered into two long-term financing arrangements fully funding the construction of the Company's power plant located in Pará, Brazil (the "Barcarena Power Plant") .

Proceeds received will be used to repay the current Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025.

The owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement").

The Company is 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").

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.

Additionally, 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").

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.

The Company is able to prepay the Barcarena Debentures, subject to customary break funding costs, and the Company is required to utilize certain excess cash flows from the Company's Brazilian operations to prepay principal.

The Barcarena Debentures are convertible to shares of one of the Company's 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 Company's LNG regasification terminals located in Pará, Brazil ("Barcarena Terminal") and Santa Catarina, Brazil .

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

Term Loan B Credit Agreement

On October 30, 2023, the Company entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to the Company in an aggregate principal amount of $856 million ("Term Loan B").

The proceeds from the Term Loan B issuance will be 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 in October 2028 if the 2025 Notes and 2026 Notes (each as defined in the Annual Report) are refinanced prior to their maturities;

if not, the Term Loan B becomes due approximately 60 days prior to the maturity of each the 2025 Notes and 2026 Notes.

Quarterly principal payments of approximately $2.1 million begin to be due starting March 2024.

The Term Loan B is guaranteed on a senior secured basis by each domestic subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report) and will be guaranteed on a senior secured basis by each foreign guarantor that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility on a post-closing basis.

The Term Loan B is and will be secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes, the Company's letter of credit facility and Revolving Facility.

Additionally the Term Loan B is secured by assets comprising our first Fast LNG project in Altamira, Mexico.

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%.

The Company may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs.

The Company is 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, the Company will be required to prepay the Term Loan B with the Company’s 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.

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 ZeroPark I to be the largest green hydrogen plant in the United States.

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.

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.

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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.

Results of Operations – Three Months Ended September 30, 2023 compared to Three Months Ended June 30, 2023 and Nine Months Ended September 30, 2023 compared to Nine Months Ended September 30, 2022

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.

Results of Operations – Three Months Ended March 31, 2024 compared to Three Months Ended December 31, 2023 and Three Months Ended March 31, 2023

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

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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.

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.

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

The tables below present our segment information for the three months ended September 30, 2023 and June 30, 2023, and for the nine months ended September 30, 2023 and September 30, 2022:

Three Months Ended September 30, 2023

(in thousands of $) Terminals and

Infrastructure Ships Total Segment Consolidation

and Other (3)

Total revenues $ 447,905 $ 66,557 $ 514,462 $ — $ 514,462

Cost of sales (1)(2)

192,343 — 192,343 (423) 191,920

Vessel operating expenses (4)

— 11,613 11,613 — 11,613

Operations and maintenance (4)

60,819 — 60,819 — 60,819

Segment Operating Margin $ 194,743 $ 54,944 $ 249,687 $ 423 $ 250,110

Three Months Ended September 30, 2023

(in thousands of $) Consolidated

Gross margin (GAAP) $ 201,440

Depreciation and amortization 48,670

Consolidated Segment Operating Margin (Non-GAAP) $ 250,110

Three Months Ended June 30, 2023

The tables below present our segment information for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023:

Three Months Ended March 31, 2024

(in thousands of $) Terminals and

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

Three Months Ended June 30, 2023

Three Months Ended March 31, 2024

(in thousands of $) Consolidated

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

Nine Months Ended September 30, 2023

Three Months Ended December 31, 2023

(in thousands of $) Terminals and

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Segment Operating Margin $ 373,154 $ 54,198 $ 427,352 $ 1,491 $ 428,843

Nine Months Ended September 30, 2023

Three Months Ended December 31, 2023

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 428,843

Nine Months Ended September 30, 2022

Three Months Ended March 31, 2023

(in thousands of $) Terminals and

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Segment Operating Margin $ 402,139 $ 78,678 $ 480,817 $ (126,586) $ 354,231

Nine Months Ended September 30, 2022

Three Months Ended March 31, 2023

(in thousands of $) Consolidated

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Consolidated Segment Operating Margin (Non-GAAP) $ 354,231

(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 realized lo sses of $0.3 million and realized gains of $141.6 million for the three and nine months ended September 30, 2023, respectively, were recognized as a reduction to Cost of sales in the segment measure.

We recognized unrealized gains of $0.4 million and unrealized losses of $107.9 million on the mark-to-market value of derivative transactions for the three and nine months ended September 30, 2023, respectively, and these gains and losses reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated stat ements of operations and comprehensive income (loss) .

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

Contract acquisition costs of $6.2 million for the three and nine months ended September 30, 2023 reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss).

(2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income (loss) .

(3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of Centrais Elétricas de Sergipe Participações S.A.

(“CELSEPAR”) and the common units of Hilli LLC in the segment measure, prior to the disposition to 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.

(1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are economic hedges of our commodity purchases and sales.

For the three months ended March 31, 2024, December 31, 2023 and March 31, 2023, Terminals and Infrastructure does not include unrealized mark-to-market gains (losses) of derivative transactions of $–, 1.5 million and $111.1 million, respectively.

In the first quarter of 2023, a realized gain of $146.1 million were recognized as a reduction to Cost of sales in the segment measure.

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

(3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to the Company's ownership of the common units of Hilli LLC in the segment measure, prior to the disposition to this investments, and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.

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

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Three Months Ended

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

Total revenues $ 447,905 $ 495,504 $ (47,599)

Cost of sales (exclusive of depreciation and amortization) 192,343 222,371 (30,028)

Operations and maintenance 60,819 33,697 27,122

Segment Operating Margin $ 194,743 $ 239,436 $ (44,693)

Nine Months Ended,

(in thousands of $) September 30, 2023 September 30, 2022 Change

(in thousands of $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change

Total revenues $ 647,737 $ 695,068 $ (47,331) $ 502,608 $ 145,129

Cost of sales (exclusive of depreciation and amortization) 229,117 259,976 (30,859) 73,798 155,319

Vessel operating expenses — 11,178 (11,178)

Operations and maintenance $ 68,548 $ 61,938 6,610 26,671 41,877

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Total revenue

Total revenue for the Terminals and Infrastructure Segment decreased by $47.6 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.

The decrease was primarily driven by decreases to revenue from LNG cargo sales to third parties, partially offset by additional gas sales in Puerto Rico and increases to the Henry Hub index.

The index forms a portion of the pricing to invoice most of our customers in this segment.

The decrease in revenue in third quarter of 2023 when compared to the second quarter of 2023 was primarily attributable to the following:

• We had no revenue from LNG cargo sales for the three months ended September 30, 2023, decreasing from $267.8 million for the three months ended June 30, 2023, as we were able to utilize all LNG purchased under our long-term supply contracts in our terminal operations.

Such decrease was offset by increases to revenue in the three months ended September 30, 2023 when compared to the three months ended June 30, 2023, due to the following:

• Volumes delivered to downstream terminal customers increased from 14.0 TBtus in the second quarter of 2023 to 20.1 TBtu in the third quarter of 2023.

We continue to support the grid stabilization project in Puerto Rico, and we recognized a full quarter of operations for our Palo Seco Power Plant during the third quarter.

We also completed the commissioning of additional power assets at the San Juan Power Plant in September.

Additionally, i n August 2023, we placed our La Paz Power Plant into service, and we began to recognize revenue from power sales from this plant in the local spot market.

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

Total revenue for the Terminals and Infrastructure Segment decreased by $265.2 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 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 nine months ended September 30, 2023 when compared to the nine months ended September 30, 2022 was primarily attributable to the following:

• Our LNG cargo sales to third parties decreased by $327.7 million for the nine months ended September 30, 2023, decreasing from $944.8 million for the nine months ended September 30, 2022 to $617.1 million nine months ended September 30, 2023.

In the third quarter of 2023, we were able to utilize all LNG purchased under our long-term supply contracts in our terminal operations.

• 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 nine months ended September 30, 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 60% for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022

Such decrease was offset by increases to revenue in the nine months ended September 30, 2023 when compared to the nine months ended September 30, 2022, due to the following:

• Volumes delivered to downstream customers were 46.1 TBtu for the nine months ended September 30, 2023 as compared to 28.5 TBtu for the nine months ended September 30, 2022, and these increased volumes were primarily attributable to our operations in Jamaica, Puerto Rico and Mexico.

• In the prior year, maintenance activities significantly lowered consumption at our facilities;

there has been 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 Plants.

Volumes delivered across from these facilities increased by 12.8 TBtu as compared to the nine months ended September 30, 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 consumed 4.7 TBtu at these power plants during the nine months ended September 30, 2023 as part of this project.

Total revenue for the Terminals and Infrastructure Segment decreased by $47.3 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023, and total revenue for the Terminals and Infrastructure Segment increased by $145.1 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

The decrease in revenue in the first quarter of 2024 when compared to the fourth quarter of 2023 was primarily attributable to decreases in the market price of natural gas.

The average Henry Hub index pricing used to invoice our downstream customers decreased by 22% for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

Volumes delivered to downstream terminal customers decreased from 22.2 TBtus in the fourth quarter of 2023 to 22.0 TBtu in the first quarter of 2024.

The increase in revenue in the first quarter of 2024 when compared to the first quarter of 2023 was primarily attributable to increased volumes delivered to our downstream customers, partially offset by reduced market pricing of natural gas.

• For the three months ended March 31, 2024, volumes delivered to downstream customers were 22.0 TBtu as compared to 12.1 TBtu for the three months ended March 31, 2023.

In 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets in the second and third quarters of 2023, and the increase in volumes in the first quarter of 2024 is primarily attributable to additional sales in Puerto Rico.

Our customer terminated the grid stabilization project in the first quarter of 2024, but we continue to sell volumes into these power plants under a new island-wide gas sale agreement signed with PREPA that will allow us to sell up to 80 TBtus annually.

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

Revenue from cargos sales was $349.3 million for the three months ended March 31, 2023.

• The average Henry Hub index pricing used to invoice our downstream customers decreased by 35% for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

Cost of sales

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

Cost of sales decreased by $30.0 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023, which was attributable to the following:

• We did not incur any cost of LNG purchased from third parties for LNG cargo sales, decreasing our cost by $76.9 million during the third quarter of 2023.

• Vessel costs increased by $23.0 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.

Vessels were used for commissioning of our La Paz Power Plant and our enhanced supply chain for our Puerto Rican operations in the second quarter, and such vessel costs were capitalized.

As these projects became operational in the third quarter we recognized higher expense associated with these vessels.

Further, certain vessels were placed into service at our terminals during the third quarter resulting in higher vessel charter costs.

• Increase in cost of LNG purchased from third parties for sale to our downstream customers of $18.4 million related to higher terminal sales;

volumes delivered to our downstream customers increased by approximately 43% in the current quarter.

Our cost to deliver these volumes decreased to $6.76 per MMBtu for the three months ended September 30, 2023 from $8.08 per MMBtu for the three months ended June 30, 2023.

Cost of sales decreased by $421.4 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022, which was attributable to the following:

• We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $212.6 million during the nine months ended September 30, 2023, resulting from no LNG cargo sales in the third quarter as well as lower cost under our LNG supply contracts for cargos sold earlier in 2023.

• Realized gains of $141.6 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.

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 decreased by $30.9 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

We incurred additional development service costs of $19.6 million in the fourth quarter of 2023.

When we perform these services for our customers, such costs are reimbursed and revenue is recognized as services are performed.

Our cost to deliver natural gas volumes decreased to $6.96 per MMBtu for the three months ended March 31, 2024 from $7.08 per MMBtu for the three months ended December 31, 2023.

Cost of sales increased by $155.3 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023, which was attributable to the following:

• Realized gain of $146.1 from the settlement of a commodity swap transaction, entered into as an economic hedge to reduce the market risks associated with commodity prices, was included as reduction of cost of sales in the first quarter of 2023.

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

• Vessel costs decreased by $37.6 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 primarily due to the capitalization of vessel costs for the commissioning of development projects, as well as, vessel costs recognized as inventory when our vessels are used to transport inventory from a supplier's facility to our storage locations and terminals.

• Cost of sales for the nine months ended September 30, 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 $15.3 million during the nine months ended September 30, 2023 due to increased volumes delivered;

we delivered 62% more volumes to our downstream terminal customers in the current period as compared to the nine months ended September 30, 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 $7.26 per MMBtu for the nine months ended September 30, 2023 from $10.78 per MMBtu for the nine months ended September 30, 2022.

The weighted-average cost of our LNG inventory balance to be used in our downstream terminal operations as of September 30, 2023 and December 31, 2022 was $7.30 per MMBtu and $10.42 per MMBtu, respectively.

Vessel operating expenses

Vessel operating expenses include direct costs associated with operating a vessel, and these costs are typically included in the Ships segment.

Once we begin to use a vessel in our terminal operations, the costs of the vessel begin to be included in the Terminals and Infrastructure segment.

For the nine months ended September 30, 2022, we incurred $11.2 million of vessel operating expenses in this segment;

we did not incur vessel operating costs in this segment during the nine months ended September 30, 2023.

We had no settlements of commodity derivative transactions in the first quarter of 2024.

• In the first quarter of 2024, we did not have any cargo sales and we delivered higher volumes to our downstream terminal customers in the current period as compared to the three months ended March 31, 2023.

delivered more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers decreased to $6.96 per MMBtu for the three months ended March 31, 2024 from $7.23 per MMBtu for the three months ended March 31, 2023.

• We recognized additional payroll and other operating costs of $21.0 million to provide services under Genera's operations and maintenance contract;

these costs are passed onto PREPA.

The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2024 and December 31, 2023 was $7.10 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 $27.1 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.

Starting in the third quarter of 2023, our subsidiary, Genera, began to provide

operations and maintenance services for PREPA's thermal generation assets, and we recognized payroll and other operating costs of $16.3 million.

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

In the third quarter, we also undertook activities to ensure that we have LNG supply available for our expanded Puerto Rican operations, including leasing berth space to place a storage vessel to service Puerto Rico, and we incurred additional lease cost associated with this berth space in the third quarter of 2023.

Operations and maintenance increased $31.3 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 .

The increase was primarily attributable to reimbursable payroll and operating costs of Genera and increased lease costs associated with our Puerto Rican operations incurred in the third quarter of 2023.

Additionally, we leased turbines to generate power at the Palo Seco Power Plant as part of the grid stabilization project in 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 nine months ended September 30, 2023.

Operations and maintenance increased by $6.6 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

The increase was primarily attributable to maintenance, logistics and other costs incurred for operating our terminals and power plants.

Operations and maintenance increased by $41.9 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023 .

The increase was primarily due to additional lease cost for turbines leased to generate power at the Palo Seco Power Plant and San Juan Power Plant as part of the grid stabilization project in Puerto Rico.

In addition, there were higher vessel operating costs included in Operations and maintenance as additional vessels started to support our terminal operations in 2024 as compared to the three months ended March 31, 2023.

Ships Segment

Three Months Ended,

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

Total revenues $ 66,557 $ 65,841 $ 716

Vessel operating expenses 11,613 11,443 170

Segment Operating Margin $ 54,944 $ 54,398 $ 546

Nine Months Ended,

(in thousands of $) September 30, 2023 September 30, 2022 Change

(in thousands of $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change

Total revenues $ 42,584 $ 63,290 $ (20,706) $ 97,917 $ (55,333)

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

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 busine ss operations.

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 in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange").

In the fourth quarter of 2022, we recognized a loss on the investment in the Hilli of $118.6 million;

this loss was recognized in Loss from equity method investments in the consolidated statements of operations and comprehensive income (loss) .

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 (income) expense, 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 September 30, 2023, four FSRUs and two LNG carriers were leased to customers under long-term or spot arrangements.

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.

The gain on sale is included in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss).

The Mazo continues to be in cold lay-up, and no vessel charter revenue was generated from the vessel.

As of December 31, 2023 and March 31, 2024, three FSRUs and one LNG carrier were leased to customers under long-term arrangements.

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

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

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

Total revenue

Total revenue for the Ships segment increased $0.7 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023 .

During the third quarter, there were no reclassifications of vessels out of the Ships segment;

there were also no significant changes the vessel charters.

Total revenue for the Ships segment decreased $107.3 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 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.

One of our vessel charters was renewed at the beginning of 2023 at a lower rate;

additionally the charters for two vessels concluded in the first quarter of 2023, lowering vessel revenue for the full nine months ended September 30, 2023 .

We plan to utilize these vessels in our operations following conversion and other upgrades starting later in 2023.

Total revenue for the Ships segment decreased $20.7 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

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

The decrease in revenue was primarily driven by end of third-party charters of Winter and Princess during the fourth quarter of 2023.

Total revenue for the Ships segment decreased $55.3 million for the three months ended March 31, 2024 as compared to the three months ended March 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, lowering vessel revenue for the three months ended March 31, 2024 .

We are now utilizing these vessels in our operations.

Vessel operating expenses

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

Vessel operating expenses increased $0.2 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.

Vessel operating expenses decreased $28.7 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 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.

Vessel operating expenses 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.

Vessel operating expenses for the three months ended March 31, 2024 were consistent with those incurred in the three months ended December 31, 2023.

Vessel operating expenses decreased $10.8 million for the three months ended March 31, 2024 as compared to the three months ended March 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.

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

Other operating results

Three Months Ended, Nine Months Ended,

(in thousands of $) September 30, 2023 June 30, 2023 Change September 30, 2023 September 30, 2022 Change

Three Months Ended,

(in thousands of $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change

Selling, general and administrative $ 70,754 $ 48,056 $ 22,698 $ 52,138 $ 18,616

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Asset impairment expense — 10,958 (10,958) — —

Loss on sale of assets, net 77,140 (21,534) 98,674 — 77,140

Total operating expenses 199,756 101,803 97,953 87,007 112,749

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Interest expense 77,344 76,951 393 71,673 5,671

Other (income) expense, net (2,271) (6,584) 4,313 16,150 (31,613) 47,763

Loss on extinguishment of debt, net — — — — 14,997 (14,997)

Other expense (income), net 19,112 (13,586) 32,698 25,005 (5,893)

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

Income before income from equity method investments and income taxes 78,294 263,675 (185,381) 170,546 (92,252)

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

Selling, general and administrative decreased $6.7 million for the three months ended September 30, 2023, compared to the three months ended June 30, 2023.

We have decreased headcount supporting our administrative activities, and we recognized a decrease to our estimate of annual incentive compensation due to the headcount reduction in the third quarter of 2023.

Selling, general and administrative decreased $8.9 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022.

The decreases were primarily due to lower share-based compensation expense in 2023, offset by higher payroll costs incurred for the nine months ended September 30, 2023 prior to our headcount reduction.

Selling, general and administrative increased $22.7 million for the three months ended March 31, 2024, compared to the three months ended December 31, 2023.

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

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

We have also recognized $5.2 million of share-based compensation costs associated with RSUs issued.

No significant allowance or share-based compensation costs were recognized during the three months ended December 31, 2023.

Selling, general and administrative increased by $18.6 million for three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

We incurred additional allowance for uncollectible receivables and share-based compensation costs associated with RSUs issued;

no share based compensation expense or allowance was recognized in the first quarter of 2023.

The remaining increase was due to additional professional fees incurred.

Transaction and integration costs

For the three months ended September 30, 2023, we did not incur significant transaction and integration costs.

For the nine months ended September 30, 2023, we incurred $4.8 million for transaction and integration costs, as compared to $12.4 million for the nine months ended September 30, 2022.

For the nine months ended September 30, 2022, we incurred transaction and integration costs primarily associated with the Sergipe Sale.

There were no such significant transactions for the nine months ended September 30, 2023.

The Company did not incur significant transaction and integration costs for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023.

Depreciation and amortization

Depreciation and amortization increased $6.6 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023 and increased $18.7 million for the nine months ended September 30, 2023 as

compared to the nine months ended September 30, 2022.

In the second quarter of 2023, we began to place assets in service as part of the grid stabilization project in Puerto Rico, including turbines we own, as well a turbines we leased under a finance lease, at the Palo Seco Power Plant.

These assets were placed into service in the May 2023, and we recognized a full quarter of depreciation in the third quarter of 2023.

Depreciation and amortization decreased by $11.7 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

The decrease is primarily attributable to the end of the term of two acquired favorable charter contract intangibles in the fourth quarter of 2023, reducing amortization expense in the first quarter of 2024.

Depreciation and amortization increased by $16.1 million for the three months ended March 31, 2024 as compared to the three months ended March 31, 2023.

The increase is primarily resulting from turbines placed into service as part of the grid stabilization project during the second and third quarters of 2023.

In addition, the Company placed the La Paz power plant into service in September 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 nine months ended September 30, 2022, we recognized asset impairment expense of $48.1 million, as the fair value of these assets was less than the carrying value, and the asset group was held for sale.

There were no such transactions for the nine months ended September 30, 2023.

In December 2023, the Company recognized an impairment of $11.0 million in conjunction with the classification as held for sale of its vessel Mazo.

There was no impairment of assets during three months ended March 31, 2024 or March 31, 2023.

Loss on sale of assets, net

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

During the fourth quarter of 2023, we completed the sale of 100% of shares in two project companies in Brazil for a total gain of $21.5 million.

Interest expense

Interest expense increased by $0.4 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023.

Increased interest expense due to borrowings under our expanded Revolving Facility and the Bridge Term Loan, as well as the issuance of the Equipment Notes and the Short-term Borrowings (each as defined below), were mostly offset by increases in capitalized interest.

Interest expense increased by $44.5 million for the nine months ended September 30, 2023 , as compared to the nine months ended September 30, 2022 .

The increase was primarily due to an increase in total principal outstanding due to additional principal balance outstanding, including obligations under the Energos Formation Transaction.

The total principal balance on outstanding facilities was $6.2 billion as of September 30, 2023 as compared to total principal outstanding of $4.5 billion as of September 30, 2022.

Other (income) expense, net

Other (income) expense, net was $(2.3) million and $(6.6) million three months ended September 30, 2023, and June 30, 2023, respectively.

Other expense (income), net was $16.2 million and $(31.6) million for the nine months ended September 30, 2023 and September 30, 2022, respectively.

Other income recognized in the three months ended September 30, 2023 was primarily comprised of a $7.8 million gain on the sale of the Golar Spirit and interest income.

This income was partially offset by foreign currency remeasurement losses and realized losses on the sale of certain investments in equity securities.

Other expense recognized in the nine months ended September 30, 2023 was primarily comprised of a $37.4 million loss on disposal of Hilli equity method investment in the Hilli Exchange.

This loss was partially offset by interest income and foreign currency remeasurement net gains.

Tax provision

We recognized a tax provision for the three months ended September 30, 2023 of $25.2 million compared to a tax provision of $15.3 million for the three months ended June 30, 2023.

Our effective tax rate for the three months ended September 30, 2023 was 28.8% compared to 11.3% for the three months ended June 30, 2023.

Our tax provision and effective tax rate primarily increased due to additional expected income tax expense related to certain of the Company's foreign subsidiaries.

We recognized a tax provision of $69.5 million for the nine months ended September 30, 2023 compared to a tax benefit of $126.2 million for the nine months ended September 30, 2022.

The significant tax benefit recognized in 2022 was primarily driven by significant discrete items, including the remeasurement of a deferred tax liability in conjunction with an internal reorganization and the tax benefit associated with the other-than-temporary impairment on our investment in CELSEPAR.

We have not recognized any significant discrete items through the third quarter of 2023.

Interest expense increased by $0.4 million for the three months ended March 31, 2024 as compared to the three months ended December 31, 2023.

The increase was primarily due to new 2029 Notes (defined below) .

Interest expense increased by $5.7 million for the three months ended March 31, 2024, as compared to the three months ended March 31, 2023.

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

The total principal balance on outstanding facilities was $7.2 billion as of March 31, 2024 as compared to total outstanding debt of $5.3 billion as of March 31, 2023.

Our borrowing costs increased by $58.9 million for the first quarter of 2024 as compared to the first quarter of 2023.

However, we have capitalized $53.2 million additional interest in current period (see Note 19 in our condensed consolidated financial statements).

Other expense (income), net

Other expense (income), net was $19.1 million, $(13.6) million and $25.0 million for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023, respectively.

The significant increase in Other expense recognized in the three months ended March 31, 2024 and December 31, 2023 was primarily due to unrealized foreign currency remeasurement losses in the first quarter of 2024 as compared to remeasurement gains in the fourth quarter of 2023.

Other expense recognized in the three months ended March 31, 2023 was primarily comprised of a $37.4 million loss on disposal of Hilli equity method investment.

This loss was partially offset by interest income, foreign currency remeasurement gains and gains on investments in equity securities.

Loss on extinguishment of debt

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

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

Income (loss) from equity method investments

We recognized income from our equity method investments of $0.5 million and $2.3 million for the three months ended September 30, 2023 and June 30, 2023, respectively.

We completed the Hilli Exchange in the first quarter of 2023, and as such, income from equity method investments in the second and third quarters of 2023 is wholly comprised of

earnings from our investment in Energos.

Our share of earnings from Energos decreased in the third quarter due to additional vessel operating expenses incurred by Energos.

We recognized income of $12.7 million from our equity method investments in the nine months ended September 30, 2023 compared to loss of $354.4 million for the nine months ended September 30, 2022.

In connection with the announcement of the sale of our investment in CELSEPAR in 2022, we recognized an other than temporary impairment of the investment in CELSEPAR of $369.2 million;

we did not have any such impairments impacting the earnings from our equity method investments in 2023.

During the three months ended March 31, 2023, we recognized income of $4.0 million from our equity method investment in Energos and $6.0 million of income from our investment in the common units of Hilli LLC for the period prior to the completion of the disposition of our investment.

We recognized a loss from our investment in Energos of $2.8 million for the three months ended December 31, 2023.

In the first quarter of 2024, we sold substantially all of our stake in Energos resulting in no income or loss from equity method investments for the three months ended March 31, 2024.

Tax provision

We recognized a tax provision for the three months ended March 31, 2024 of $21.6 million compared to a tax provision of $46.0 million for the three months ended December 31, 2023 and a tax provision of $29.0 million for the three months ended March 31, 2023.

The increase in tax provision recognized in the fourth quarter of 2023 was primarily driven by increase in valuation allowance against losses in foreign jurisdictions.

Factors Impacting Comparability of Our Financial Results

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• 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 98% of our LNG volumes from third parties for the nine months ended September 30, 2023.

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

We expect to deploy our first Fast LNG unit upon the completion of commissioning.

We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 99% of our LNG volumes from third parties for the three months ended March 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.

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 three and nine months ended September 30, 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, 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 the Hilli Exchange, and in the fourth quarter of 2022, we sold our interest in 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.

Our results of operations for the three months ended March 31, 2024 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant, certain industrial end-users and our Miami Facility.

We have completed construction and commissioning of our Barcarena Facility and Santa Catarina Facility and expect to place these assets into service in 2024.

We are also continuing to develop our 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 will 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.

Liquidity and Capital Resources

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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 have also incurred significant capital costs to deploy 350MW of temporary power as part of the grid stabilization project in Puerto Rico.

We expect the current working capital position to improve based on:

(1) following September 30, 2023, we have borrowed under our new Term Loan B Agreement, totaling $856 million;

(2) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil;

We expect the current working capital position to improve based on the following:

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

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

(4) our credit 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;

(4) expected cash flows generated from the temporary power project and from sales of our own LNG

generated by our first deployed Fast LNG unit;

and (5) 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 Fast LNG.

and (5) 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.

In addition, we are exploring capital raising and strategic alternatives for our business in Brazil, which may include a

merger transaction, sale of a minority interest and/ or initial public offering.

There can be no assurance that the exploration

of capital raising and strategic alternatives will result in any agreements or transactions, or that, if completed, any

agreements or transactions will be successful or on attractive terms.

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.

We have assumed total committed expenditures for all completed and existing projects to be approximately $6,162 million, with approximately $4,815 million having already been paid through September 30, 2023.

This estimate represents the committed expenditures for our Fast LNG project, as well as committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility and committed capital expenditures to support our grid stabilization project in Puerto Rico.

We expect fully completed Fast LNG units to cost between $1.0 billion and $1.6 billion per unit.

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 $1,619 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 $1,027 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 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.

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

As of September 30, 2023, we have spent approximately $128.6 million to develop the Pennsylvania Facility.

As of March 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.

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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 $61.5 million during the nine months ended September 30, 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.

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 September 30, 2023.

The following table summarizes certain contractual obligations, including principal and interest, in place as of March 31, 2024.

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

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

The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of September 30, 2023.

The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of March 31, 2024.

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

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

Subsequent to September 30, 2023, we entered into the BNDES Credit Agreement, Barcarena Debentures and Term Loan B Credit Agreement (each defined and described in Note 24.

Subsequent events).

Proceeds from these new credit arrangements have been or will be used to refinance the Bridge Term Loan and the Barcarena Term Loan on a long term basis, and as such, these principal balances have been shown as non-current on the condensed consolidated balance sheets as of September 30, 2023.

Purchase obligations

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

For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of September 30, 2023.

We have construction purchase commitments in connection with our development projects, including our Fast LNG project, La Paz Facility, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and committed capital expenditures to support our grid stabilization project in Puerto Rico.

For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of March 31, 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 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.

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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.

The following table summarizes the changes to our cash flows for the nine months ended September 30, 2023 and 2022, respectively :

Nine Months Ended September 30,

The following table summarizes the changes to our cash flows for the three months ended March 31, 2024 and 2023, respectively :

Three Months Ended March 31,

(in thousands of $) 2024 2023 Change

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Financing activities 157,617 43,221 114,396

Net (decrease) increase in cash, cash equivalents, and restricted cash $ (604,306) $ 144,855 $ (749,161)

Net decrease in cash, cash equivalents, and restricted cash $ 7,887 $ (219,907) $ 227,794

Cash provided by operating activities

Our cash flow provided by operating activities was $537.2 million for the nine months ended September 30, 2023, which increased by $446.1 million from cash provided by operating activities of $91.1 million for the nine months ended

September 30, 2022.

The increase in cash provided by operating activities for the nine months ended September 30, 2023 was primarily 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.

Our cash flow provided by operating activities was $70.1 million for the three months ended March 31, 2024, which decreased by $130.1 million from cash provided by operating activities of $200.1 million for the three months ended March 31, 2023.

Our net income for the three months ended March 31, 2024, when adjusted for non-cash items, decreased by $11.3 million from the three months ended March 31, 2023.

The decrease in cash provided by operating activities for the three months ended March 31, 2024 was mainly driven by increases in inventory and other changes in working capital.

Cash used in investing activities

Our cash flow used in investing activities was $2,065.6 million for the nine months ended September 30, 2023, which increased by $1,869.6 million from cash used in investing activities of $196.0 million for the nine months ended September 30, 2022.

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

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

Cash outflows for investing activities during the nine months ended September 30, 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 .

Our cash flow used in investing activities was $219.8 million for the three months ended March 31, 2024, which decreased by $243.5 million from cash used in investing activities of $463.3 million for the three months ended March 31, 2023.

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

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

Cash outflows for investing activities during the three months ended March 31, 2023 were used primarily for continued development of our Fast LNG project.

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.

Cash provided by financing activities

Our cash flow provided by financing activities was $924.1 million for the nine months ended September 30, 2023, which increased by $674.4 million from cash provided by financing activities of $249.7 million for the nine months ended September 30, 2022.

In December 2022, our Board of Directors approved and declared a dividend of $626.3 million, representing $3.00 per Class A share;

such dividend payment was made in January 2023.

We have borrowed under our expanded Revolving Facility, Bridge Term Loans, Equipment Notes, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $1,768.7 million.

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

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

Cash provided by financing activities during the nine months ended September 30, 2022 was due to proceeds from issuance of debt of $1.9 billion, offset by repayments of debt of $1.5 billion, payment of dividends of $75.1 million and payments related to tax withholdings for shared-based compensation of $72.6 million.

Our cash flow provided by financing activities was $157.6 million for the three months ended March 31, 2024, which increased by $114.4 million from cash provided by financing activities of $43.2 million for the three months ended March 31, 2023.

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

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

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

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

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

Our cash flow provided by financing activities for the three months ended March 31, 2023 included a dividend payment of $626.3 million that was made in January 2023.

Throughout the first quarter of 2023 we also borrowed under our expanded Revolving Facility for total additional borrowings of $700.0 million, with such borrowings primarily used to fund the ongoing development of our Fast LNG project.

Long-Term Debt and Preferred Stock

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

Bridge Term Loan Credit Agreement

On August 3, 2023, we entered into a Bridge Term Loan Credit Agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) to the Company in an aggregate principal amount of $400 million.

Bridge Term Loan proceeds may be used for working capital and other general corporate purposes.

The Bridge Term Loans will mature on August 1, 2024 and are payable in full on the maturity date.

The Bridge Term Loans were repaid in full without penalty using proceeds from the Term Loan B which closed after September 30, 2023.

The Bridge Term Loans were guaranteed on a senior secured basis by each domestic and foreign subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report).

The Bridge Term Loans were secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes and Revolving Facility.

The Bridge Term Loan Agreement contained usual and customary representations and warranties, and usual and customary affirmative and negative covenants, including requirements to maintain certain levels of total debt to capitalization and total first lien debt to EBITDA, and the ratios required to be maintained were consistent with the requirements under the Revolving Facility.

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 the 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.

2029 Senior Secured Notes

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

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

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

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

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

The 2029 Notes may limit the Company’s ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain conditions and qualifications.

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

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

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

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

BNDES Term Loan

The owner of our power plant under construction in Pará, Brazil (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").

In the first quarter of 2024, lenders funded $273.4 million under the BNDES Credit Agreement.

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

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

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

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

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

EB-5 Loan Agreement

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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 third quarter of 2023, $37.9 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 we 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 September 30, 2023, we had $161.8 million due under repurchase arrangements with a weighted average interest rate of 9.74%.

Revolving Facility

In the first three quarters of 2023, we entered into amendments of our Revolving Facility which increased the commitments by $426.6 million, for a total capacity of $866.6 million.

The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed, and no changes were made to the maturity date or covenants.

In conjunction with these amendments, we incurred an additional $7.0 million in fees which have been capitalized within Other non-current assets.

It is expected that the loan will be secured by our green hydrogen facility, and

we have provided a guarantee of the obligations under the EB-5 Loan Agreement.

In the three months ended March 31, 2024, an additional $36.3 million was funded under the EB-5 Loan Agreement.

PortoCem BTG Loan

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

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

We provided a parent company guarantee to the lenders under the PortoCem BTG Loan.

The PortoCem BTG Loan contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

No financial debt covenant compliance is required under this loan facility.

In April 2024, we repaid the PortoCem BTG Loan with proceeds from a short term credit note.

Equipment Notes

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

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

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

Debt and lease restrictions

We are required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023.

We were in compliance with all covenants as of September 30, 2023.

We were in compliance with all covenants as of March 31, 2024.

Critical Accounting Policies and Estimates

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

As of September 30, 2023 , there have been no significant changes to our critical accounting estimates since our Annual Report.

As of March 31, 2024 , there have been no significant changes to our critical accounting estimates since our Annual Report.

Recent Accounting Standards

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

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

For descriptions of recently issued accounting standards, see Note 3 to our notes to condensed consolidated financial statements included elsewhere in this Quarterly Report.

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis