New Fortress Energy Inc. 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and under similar headings in the Annual Report on Form 10-K for the year ended December 31, 2023 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis. The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions. Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries. Overview We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in our Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Very-Low Carbon Future.” Our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships. Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third-party suppliers and from our own liquefaction facility in Miami, Florida. 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 and fleet. Our Ships segment includes all vessels which are leased to customers under long-term arrangements. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire. 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 29 Table of Contents Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility, each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers. Montego Bay Facility The Montego Bay Facility serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue power plant in Montego Bay, Jamaica ("Bogue Power Plant"). Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 60,000 MMBtu of LNG per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users. Old Harbour Facility The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay agreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers. San Juan Facility Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant, industrial end-user customers in Puerto Rico, and after being awarded a new gas sale agreement in the first quarter of 2024, PREPA's gas-fired power plants throughout the island of Puerto Rico. In 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 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. 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 30 Table of Contents improving reliability of power generation in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees. The service period under the contract commenced on July 1, 2023. La Paz Facility In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power. We placed the La Paz Power Plant into service in the third quarter of 2023. In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. We executed the final long-form gas sales agreement in the second quarter of 2023, which is subject to certain conditions precedent including the execution of the final agreement to sell the La Paz Power Plant. Miami Facility Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers. Our LNG Supply and Cargo Sales NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts expected to commence in 2027; 3) our Miami Facility; and 4) supply from our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to commence in 2027. Finally, we plan to commence production from our 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, we plan to further mitigate our exposure to variability in LNG prices. In 2022 and 2023, our revenue and results of operations have benefited from selling cargos into the global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals. Our Current Operations – Ships Our Ships segment includes Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are leased to customers under long-term arrangements. At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and described in more detail below, we 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 vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook ) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) 31 Table of Contents such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos. Our Development Projects Our projects currently under development include our development of a series of modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); our LNG terminal (“Ireland Facility”) and power plant in Ireland, and our first green hydrogen project ("ZeroPark I"). We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations. The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects. We describe each of our current development projects below. Fast LNG We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. Our “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 were constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of liquefaction projects. In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. Our first Fast LNG unit has been deployed offshore to Altamira, Mexico, and we expect to deploy additional units over the next two years. We describe our currently planned projects below. Altamira 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 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. The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks. Louisiana In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of 32 Table of Contents exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG. Lakach We have been in discussions with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. Our initial agreements were terminated in the fourth quarter of 2023, however, NFE continues to be in active discussions with Pemex to develop or monetize an offshore project. Puerto Sandino Facility We are developing an offshore liquefied natural gas receiving and storage facility off the coast of Puerto Sandino, Nicaragua, as well as an onshore regasification facility. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024. Barcarena Facility The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of processing over one million MMBtu from LNG per day and storing up to 160,000 cubic meters of LNG. We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility. We substantially completed our Barcarena Facility in 2022 and expect to commence operations, including delivery to the Alunorte Alumina Refinery in the first half of 2024. The Barcarena Facility will also supply our new 630MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”). The power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid. We expect to complete the Barcarena Power Plant and begin delivering power to nine committed offtakers for 25 years beginning in 2025. In 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 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 half of 2024. Ireland Facility We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We are 33 Table of Contents 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. ZeroParks In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies. Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the western hemisphere and numerous petrochemical manufacturers, many of which require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I and expect to commence operations on the first phase in the first half of 2025. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect 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. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending. On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue. 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. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our 34 Table of Contents profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets. Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business. The tables below present our segment information for the three months ended March 31, 2024, December 31, 2023 and March 31, 2023: Three Months Ended March 31, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 647,737 $ 42,584 $ 690,321 $ — $ 690,321 Cost of sales (1)(2) 229,117 — 229,117 — 229,117 Vessel operating expenses (4) — 8,396 8,396 — 8,396 Operations and maintenance (4) 68,548 — 68,548 — 68,548 Segment Operating Margin $ 350,072 $ 34,188 $ 384,260 $ — $ 384,260 Three Months Ended March 31, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 333,769 Depreciation and amortization 50,491 Consolidated Segment Operating Margin (Non-GAAP) $ 384,260 Three Months Ended December 31, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 695,068 $ 63,290 $ 758,358 $ — $ 758,358 Cost of sales (2) 259,976 — 259,976 (1,491) 258,485 Vessel operating expenses (4) — 9,092 9,092 — 9,092 Operations and maintenance (4) 61,938 — 61,938 — 61,938 Segment Operating Margin $ 373,154 $ 54,198 $ 427,352 $ 1,491 $ 428,843 35 Table of Contents Three Months Ended December 31, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 366,679 Depreciation and amortization 62,164 Consolidated Segment Operating Margin (Non-GAAP) $ 428,843 Three Months Ended March 31, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 502,608 $ 97,917 $ 600,525 $ (21,394) $ 579,131 Cost of sales (2) 73,798 — 73,798 111,140 184,938 Vessel operating expenses (4) — 19,239 19,239 (5,948) 13,291 Operations and maintenance (4) 26,671 — 26,671 — 26,671 Segment Operating Margin $ 402,139 $ 78,678 $ 480,817 $ (126,586) $ 354,231 Three Months Ended March 31, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 319,856 Depreciation and amortization 34,375 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 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. Terminals and Infrastructure Segment Three Months Ended (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 Operations and maintenance $ 68,548 $ 61,938 6,610 26,671 41,877 Segment Operating Margin $ 350,072 $ 373,154 $ (23,082) $ 402,139 $ (52,067) 36 Table of Contents Total revenue 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 Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide operations and maintenance services to PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue. Cost of sales 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. 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. While we 37 Table of Contents 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 $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 $) March 31, 2024 December 31, 2023 Change March 31, 2023 Change Total revenues $ 42,584 $ 63,290 $ (20,706) $ 97,917 $ (55,333) Vessel operating expenses 8,396 9,092 (696) 19,239 (10,843) Segment Operating Margin $ 34,188 $ 54,198 $ (20,010) $ 78,678 $ (44,490) Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of December 31, 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 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. 38 Table of Contents Vessel operating expenses Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli prior to the Hilli Exchange discussed above. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter. Vessel operating expenses 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, (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 Transaction and integration costs 1,371 2,159 (788) 494 877 Depreciation and amortization 50,491 62,164 (11,673) 34,375 16,116 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 Operating income 184,504 327,040 (142,536) 267,224 (82,720) Interest expense 77,344 76,951 393 71,673 5,671 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) Income (loss) from equity method investments — (2,766) 2,766 9,980 (9,980) Tax provision (benefit) 21,624 46,037 (24,413) 28,960 (7,336) Net income $ 56,670 $ 214,872 $ (158,202) $ 151,566 $ (94,896) Selling, general and administrative Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors, and screening costs for projects that are in initial stages and development is not yet probable. Selling, general and administrative 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. 39 Table of Contents 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 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 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 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 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). 40 Table of Contents 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 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 Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons: • Our historical financial results do not reflect our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 99% of our 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 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 41 Table of Contents 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 We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. Our significant capital projects, primarily our first FLNG unit, are nearing completion, and as with many capital projects, a significant portion of the overall capital spending becomes due near the completion of the project. We expect the current working capital position to improve based on the following: (1) expected cash flows generated from 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; 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. 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. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. 42 Table of Contents We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments. As of 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. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106.1 million, has been capitalized, and to date, we have repurposed approximately $16.8 million of engineering and equipment to our Fast LNG project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities. Contractual Obligations We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations, including principal and interest, in place as of March 31, 2024. (in thousands of $) Total Less than Year 1 Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 10,470,985 $ 570,236 $ 4,287,510 $ 1,961,423 $ 3,651,816 Purchase obligations 11,665,066 1,476,615 1,561,737 1,104,055 7,522,659 Lease obligations 995,127 160,182 276,190 220,043 338,712 Total $ 23,131,178 $ 2,207,033 $ 6,125,437 $ 3,285,521 $ 11,513,187 Long-term debt obligations For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report. The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of March 31, 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. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above. Purchase obligations We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of 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. Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, gas turbines and a land lease. 43 Table of Contents Cash Flows 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 Cash flows from: Operating activities $ 70,050 $ 200,140 $ (130,090) Investing activities (219,780) (463,268) 243,488 Financing activities 157,617 43,221 114,396 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 $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 $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 $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. 44 Table of Contents Long-Term Debt and Preferred Stock The terms of our debt instruments and associated obligations have been described in our Annual Report. There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below. 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. 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 capacity reserve contracts. 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. 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 On July 21, 2023, we entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100.0 million, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by our green hydrogen facility, and 45 Table of Contents 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 4.0:1.0. 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 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 to our notes to condensed consolidated financial statements included elsewhere in this Quarterly Report.