1 New Fortress Energy Inc. Condensed Consolidated Statements of Cash Flows For the three months ended March 31, 2025 and 2024 (Unaudited, in thousands of U.S. dollars) Three Months Ended March 31, 2025 2024 Cash flows from operating activities Net (loss) income $ (197,373) $ 56,670 Adjustments for: Depreciation and amortization 63,353 50,491 Deferred taxes (4,740) (6,822) Loss on asset sales — 77,140 (Earnings) recognized from vessels chartered to third parties transferred to Energos (13,082) (23,952) Loss on the disposal of equity method investment — 7,222 Other (6,635) 39,287 Changes in operating assets and liabilities: (Increase) in receivables (7,001) (8,656) Decrease (increase) in inventories 7,622 (85,539) (Increase) in other assets (1,074) (19,394) Decrease in right-of-use assets 30,848 57,190 Increase in accounts payable/accrued liabilities 130,433 63,208 (Decrease) in amounts due to affiliates (6,780) (3,479) (Decrease) in lease liabilities (42,888) (62,090) Increase (decrease) in other liabilities 15,612 (71,226) Net cash (used in) provided by operating activities (31,705) 70,050 Cash flows from investing activities Capital expenditures (340,470) (683,449) Sale of equity method investment — 136,365 Asset sales — 328,999 Other investing activities 4,555 (1,695) Net cash used in investing activities (335,915) (219,780) Cash flows from financing activities Proceeds from borrowings of debt 901,733 2,164,687 Payment of deferred financing costs (26,093) (25,781) Repayment of debt (664,062) (1,944,044) Payment of dividends (3,460) (32,326) Other financing activities (3,662) (4,919) Net cash provided by financing activities 204,456 157,617 Impact of changes in foreign exchange rates on cash and cash equivalents 34,332 (3,768) Net (decrease) increase in cash, cash equivalents and restricted cash (128,832) 4,119 Cash, cash equivalents and restricted cash – beginning of period 965,577 310,814 Cash, cash equivalents and restricted cash – end of period $ 836,745 $ 314,933 Supplemental disclosure of non-cash investing and financing activities: Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions $ (62,874) $ (117,304) Accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions 366,358 623,318 Principal payments on financing obligation to Energos by third party charters (9,871) (2,912) Class A convertible preferred stock issued and debt assumed in the PortoCem Acquisition — (125,198)
2 The following table identifies the balance sheet line-items included in Cash and cash equivalents and Restricted cash presented in the Condensed Consolidated Statements of Cash Flows: Three Months Ended March 31, 2025 2024 Cash and cash equivalents $ 447,862 $ 143,457 Restricted cash 379,537 171,476 Cash and cash equivalents and restricted cash classified as held for sale (Note 4) 9,346 — Cash, cash equivalents and restricted cash – end of period $ 836,745 $ 314,933
3 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” in the Annual Report on Form 10-K for the year ended December 31, 2024 (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. 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 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. We placed our first floating liquefaction unit, which we refer to as "Fast LNG" or "FLNG", into service in the fourth quarter of 2024, and we plan to source a portion of our LNG needs from this facility. The Terminals and Infrastructure segment includes all terminal operations in Jamaica (prior to the sale of our Jamaica Business (as defined below)), Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal, logistics or sub-charter operations, which allows us to optimally manage our LNG supply and fleet. Our Ships segment includes certain vessels which are currently chartered under long-term arrangements to third parties and are part of the Energos Formation Transaction (defined below). Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire, and these vessels are expected to be included in our Terminals and Infrastructure segment at such time. In March 2025, we entered into an equity and asset purchase agreement (the "EAPA") to sell our Jamaica business, including operations at the LNG import terminal in Montego Bay, the offshore floating storage and regasification terminal
4 in Old Harbour and the 150 megawatt Combined Heat and Power Plant in Clarendon, along with the associated infrastructure (the "Jamaica Business") for cash consideration of approximately $1.06 billion, subject to certain purchase price adjustments. On May 14, 2025, we completed the sale of the Jamaica Business and received net proceeds of approximately $678 million, with additional $99 million proceeds held in escrow and to be returned to the Company on the release dates as stated in the EAPA. Our Current Operations – Terminals and Infrastructure Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, and Jamalco, a bauxite mining and alumina producer in Jamaica, prior to the sale of the Jamaica Business, as well as the Puerto Rico Electric Power Authority (“PREPA”) and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility, each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers. San Juan Facility Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and industrial end-user customers in Puerto Rico. In 2023, we entered into agreements for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas. Our customer was contracted by the U.S. Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 350MW of duel-fuel power generation using our gas supply in less than 180 days. In March 2024, our contract to provide emergency power services to support the grid stabilization project was terminated, and we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA. We were also awarded a gas sale agreement with PREPA to supply up to 80 TBtu annually to PREPA's gas-fired power plants, including to the turbines that were sold to PREPA. The contract initially has a one year term that is renewable annually for three additional annual periods. In March 2025, the agreement was amended to extend the term by 100 days to June 2025. We are pursuing a $659 million request for equitable adjustment related to the early termination of our contract to provide emergency power services. The actual amount of any such adjustment and the timing of any related payments may be materially different than management’s current estimate. As a result, the Company cannot offer any assurance as to the actual amount that may be recovered pursuant to such request or subsequent claim, if any. In 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-year contract for the operation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and improving reliability of power generation in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees. 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.
5 In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. In the third quarter of 2024, we executed a 10-year gas sales agreement to supply natural gas to additional CFE facilities on take- or-pay basis. Santa Catarina Facility We placed our Santa Catarina Facility in service in the fourth quarter of 2024. The Santa Catarina Facility is located on the southern coast of Brazil and consists of an FSRU with a processing capacity of approximately 500,000 MMBtu from LNG per day and LNG storage capacity of up to 138,000 cubic meters. We have developed and constructed a 33-kilometer, 20-inch pipeline that connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day of natural gas. In August 2024, we acquired 100% of the outstanding equity interest of Usina Termeletrica de Lins S.A. ("Lins"), which owns key rights and permits to develop a natural gas-fired power plant for up to 2.05GW located in the State of Sao Paulo, within the city limits of Lins. We expect to participate in the power auctions anticipated to occur in 2025 in Brazil, and to the extent that NFE is successful in these auctions, we plan to develop a gas-fired power plant using natural gas from the Santa Catarina Facility. Montego Bay Facility The Montego Bay Facility serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue power plant in Montego Bay, Jamaica ("Bogue Power Plant"). 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. We no longer own the Montego Bay Facility after we completed the sale of the Jamaica Business, and starting in the second quarter of 2025, we will no longer reflect the results of operations from the Montego Bay Facility in our financial statements. Old Harbour Facility The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay agreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers. We no longer own the Old Harbour Facility and CHP Plant after we completed the sale of the Jamaica Business, and starting in the second quarter of 2025, we will no longer reflect the results of operations from the Old Harbour Facility and CHP Plant in our financial statements. Our LNG Supply and Cargo Sales NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) our own FLNG production; and 3) additional LNG supply contracts expected to commence in 2027. Our first FLNG facility began to produce LNG in July
6 2024, and we expect to generate up to 70 TBtu annually from this facility. When expected production from FLNG is combined with our commitments to purchase and receive physical delivery of LNG volumes, we expect to have sufficient supply for 100% of our committed volumes for each of our downstream terminals inclusive of our San Juan Facility, La Paz Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to commence in 2027 and 2029. Geopolitical events have substantially impacted and may continue to impact the natural gas and LNG markets, which have experienced significant volatility in recent years. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Additionally, with our own Fast LNG production, we plan to further mitigate our exposure to variability in LNG prices, and our long- term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals. Our Current Operations – Ships Our shipping assets include Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"). Our shipping assets are included in both of our operating segments. Certain vessels are currently chartered to third parties under long-term arrangements and are part of the Energos Formation Transaction (defined below); such vessels are included in our Ships segment. At the expiration of third party charters of these vessels, we plan to utilize these vessels for our own operational purposes. Vessels we operate at our terminal operations or that we decide to sub-charter are included in our Terminals and Infrastructure segment. In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of eleven vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos. Our Development Projects Our projects currently under development include our development of a series of modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant located in Pará, Brazil; our LNG terminal (“Ireland Facility”) and power plant in Ireland, our first green hydrogen project ("ZeroPark I") and Klondike Digital Infrastructure, our newly-launched power and data center infrastructure business ("Klondike"). 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-
7 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 FSUs will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application. Fast LNG is anchored by key benefits over conventional liquefaction projects. In particular, we believe installing modular equipment in a shipyard will meaningfully expedite timelines. In addition, placing solutions offshore provides greater access to natural gas and optimized marine logistics. We describe our operational and planned FLNG projects below. Altamira Our first Fast LNG unit has been deployed off the coast of Altamira, Tamaulipas, Mexico, and was placed into service in the fourth quarter of 2024. The 1.4 million ton per annum (“MTPA”) FLNG unit utilizes CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. This first FLNG unit has been fully commissioned, and we are in the process of increasing available liquefaction capacity through optimization projects. We expect to deploy up to two 1.4MTPA additional FLNG units onshore at the existing Altamira LNG import facility. The terminal also would source feedgas from the CFE from the Sur de Texas-Tuxpan Pipeline. The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks. Louisiana In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG. Lakach We have been in discussions with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. Our initial agreements were terminated in the fourth quarter of 2023, however, NFE continues to be in active discussions with Pemex to develop or monetize an offshore project.
8 Puerto Sandino Facility We are developing a liquefied natural gas receiving, transloading and regasification facility in Puerto Sandino, Nicaragua, as well as a pipeline connecting the facility with our Puerto Sandino Power Plant. We have entered into a 25- year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. Construction of the terminal and power plant is substantially complete; however, we will determine timing of final commissioning and commencement under our PPA based on the most optimal use of our LNG supply chain. As part of our long-term strategy, we are also evaluating solutions to optimize power generation and delivery to other markets, connected to our power plant through a regional transmission line. Barcarena Facility The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of delivering almost 600,000 MMBtu from LNG per day and storing up to 160,000 cubic meters of LNG. We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility. The Barcarena Facility will also supply our new 630MW combined cycle natural gas-fired power plant located in Pará, Brazil (the “Barcarena Power Plant”). The power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid. We expect to complete the Barcarena Power Plant in 2025. In March 2024, we closed the acquisition of PortoCem Geração de Energia S.A. ("PortoCem"), a wholly-owned subsidiary of Ceiba Fundo de Investimento em Participações Multiestratégia- Investimento no Exterior ("Ceiba Energy"). PortoCem is the owner of a 15-year 1.6GW capacity reserve contract in Brazil. We have transferred the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE is building the 1.6 GW simple cycle, natural gas-fired power plant ("PortoCem Power Plant") to supply the capacity reserve contract using gas from the Barcarena Facility. We expect the PortoCem Power Plant to be completed in 2026. Ireland Facility We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála ("ABP"), Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We challenged this decision, and in September 2024, the High Court of Ireland ruled that ABP did not have appropriate grounds for the denial of our permit. In March 2025, APB withdrew their appeal to the September 2024 High Court decision. ABP is now reconsidering our planning application in accordance with Irish Law. Further, in March 2025, ABP granted our application to construct a 600 MW power plant and a separate application to construct the 220 kV electricity interconnect. We are able to fuel this power plant via our LNG marine import terminal, if approved, or using gas provided from our permitted pipeline interconnection. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, which could preclude the development of this project; however, management continues to assess all options in respect of future developments for the land held. 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
9 to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies. Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the western hemisphere and numerous petrochemical manufacturers, many of which require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect ZeroPark I to be the largest green hydrogen plant in the United States. Klondike In 2024, we launched Klondike, a power and data center development business dedicated to working with hyperscale customers to build and operate data centers. This venture comes in response to a significant need for turnkey digital infrastructure to support the next stage of explosive growth in artificial intelligence. Klondike will develop independent power sources that utilize and provide behind-the-meter on-site power. This innovative approach is designed to address all major constraints of digital infrastructure development, providing grid stability, significant transmission capacity, power reliability, energy cost savings, and scalability. This approach not only reduces the demand for power from the grid but also contributes power back to it. Klondike plans to develop a geographically diverse portfolio of data center sites to satisfy the requirements of hyperscale users. Klondike has more than 1,000 acres of developable land across sites in Brazil, Ireland, and the United States that it either owns or leases. These locations have, or will have, large existing power plants or permits in process to build several gigawatts of power, connectivity to fiber networks, access to transmission and water. Recent Developments Credit agreement amendments On May 12, 205, the Company entered into the following credit agreement amendments: The Company entered into the Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”) which amends that certain Credit Agreement, dated as of April 15, 2021 (as amended, restated or otherwise modified from time to time, the “Existing RCF” and the Existing RCF as amended by the Twelfth Amendment, the “Amended RCF”), by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and as collateral agent. Among other things, the Twelfth Amendment waives the requirement that the Company pay 75% of net proceeds from certain asset sales to repay indebtedness, allowing the Company to apply $270,000 of proceeds from the sale of the Jamaica Business to the extended tranche of the Existing RCF prior to September 30, 2025, when such amount was due. The Company plans to use the remaining proceeds to reinvest in the Company’s business and repay indebtedness under the Amended TLA (as defined below). The Company entered into the Fifth Amendment to Credit Agreement (the “Fifth Amendment”) which amends that certain Credit Agreement, dated as of July 19, 2024 (as amended, restated or otherwise modified from time to time, the “Existing TLA” and the Existing TLA as amended by the Fifth Amendment, the “Amended TLA”). The Company entered into the Eighth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement (the “Eighth Amendment”) which amends that certain Uncommitted Letter of Credit and Reimbursement Agreement, dated as of July 16, 2021 (as amended, restated or otherwise modified from time to time, the “Existing ULCA” and the Existing
10 ULCA as amended by the Eighth Amendment, the “Amended ULCA”), by and among the Company, the guarantors from time to time party thereto, Natixis, New York Branch, as Administrative Agent, Natixis, New York Branch, as ULCA Collateral Agent, Natixis, New York Branch, and each of the other financial institutions party thereto, as Lenders and Issuing Banks. The Fifth Amendment, the Eighth Amendment and the Twelfth Amendment are referred to herein collectively as the “Amendments;” the Amended TLA, the Amended ULCA and the Amended RCF are referred to herein collectively as the “Amended Credit Agreements.” The Existing TLA, the Existing ULCA and Existing RCF are referred to herein collectively as the “Existing Credit Agreements.” The Twelfth Amendment, among other things, (i) provides for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio contained therein for the fiscal quarter ending June 30, 2025, (ii) permits $270,000 of proceeds from the sale of the Jamaica Business to be used to prepay and terminate a portion of loans and commitments currently outstanding and otherwise does not require the proceeds of the sale of the Jamaica Business to be used to prepay loans and commitments and (iii) provides that the asset sale sweep mandatory prepayment will now terminate effectiveness once aggregate commitments are reduced to $550,000 from $600,000. The Fifth Amendment, among other things, (i) requires $55,000 of proceeds from the sale of the Jamaica Business to be used to prepay a portion of loans currently outstanding and otherwise does not require the proceeds from the sale of the Jamaica Business to be used to prepay loans; (ii) increases the applicable margin to 6.70% for SOFR loans and 5.70% for Base Rate Loans and implements a SOFR floor of 4.30% and a base rate floor of 5.30%; (iii) requires the Company to make mandatory prepayments with 12.5% of proceeds of a $659,000 request for equitable adjustment and any other proceeds related to the early termination of our FEMA contracts, if and when such proceeds are received, to pay down a portion of the indebtedness outstanding under loans thereunder and, in the case of certain asset sales, reduce the commitments thereunder. Additionally, the Fifth Amendment amends certain of the financial covenants. After giving effect to the Fifth Amendment, the consolidated first lien debt ratio cannot exceed (i) 8.75 to 1.00, for the fiscal quarters ending March 31, 2025, (ii) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (iii) 6.50 to 1.00, for the fiscal quarter ending December 31, 2025, (iv) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 and September 30, 2026 and (v) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter. The Fifth Amendment added a fixed charge coverage ratio covenant and removed the debt to total capitalization covenant to the Amended TLA. Commencing with the fiscal quarter ending March 31, 2025, the Company cannot permit the fixed charge coverage ratio for the Company and its restricted subsidiaries to be less than or equal to 0.80 to 1.00 for the fiscal quarter ending March 31, 2025 and, for the fiscal quarter ending September 30, 2025 and each fiscal quarter thereafter, 1.00 to 1.00. Neither the first lien debt ratio covenant nor the fixed charge coverage ratio covenant will be tested for the fiscal quarter ending June 30, 2025. After giving effect to the Fifth Amendment, the financial covenants set forth above are consistent with the corresponding financial covenants in the Amended RCF and Amended LCF. The Eighth Amendment, among other things, provides for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio contained therein for the fiscal quarter ending June 30, 2025. Further to the above, the Amendments each added a covenant limiting the amount of cash the Company can use to repurchase outstanding senior secured notes due 2026, other than payments to avoid springing maturities in respect thereof or with proceeds of certain permitted debt or equity refinancing transactions. Sale of Jamaica Business On May 14, 2025, the Company completed the sale of the Jamaica Business to Excelerate Energy Limited Partnership (“EELP”), a subsidiary of Excelerate Energy, Inc., for $1.055 billion in cash, subject to certain purchase price adjustments. In conjunction with closing, the Company repurchased all outstanding South Power Bonds for $227,157, including a 1.0% prepayment penalty and accrued interest. After the repayment of debt, the Company received net proceeds of
11 approximately $678,480, with an additional $98,635 proceeds held in escrow and to be returned to the Company on the release dates as stated in the EAPA. As a result of the Amended Agreements, the Company repaid and permanently reduced the Revolving Facility commitments of $270,000 and repaid $55,000 of the Term Loan A Credit Agreement with the sale proceeds. Other Matters On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending. On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue. On September 26, 2024, the United States Coast Guard ("USCG") filed a Letter of Recommendation with FERC in which it assessed our Letter of Intent dated April 12, 2024, and our Waterway Suitability Assessment, dated August 26, 2024, in respect of future ship to ship transfers with alternative vessels, and recommended against the allowance of the proposed operations. Further, on September 26, 2024, the USCG issued a Letter of Warning in respect of our ongoing ship to ship transfers of LNG operations within the San Juan port limits. On October 21, 2024, we filed an appeal with the USCG under 33 CFR 160.7. In December 2024 and February 2025, we submitted an updated Letter of Intent and Waterway Suitability Assessments detailing our alternative operational plans to the USCG and are working collaboratively with the USCG to obtain a new Letter of Recommendation to FERC in support of our operations, which we expect to be imminently forthcoming. In concert with our collaboration with the USCG regarding our new operational plans, we withdrew our appeal on February 14, 2025. On October 25, 2024, FERC issued a notice of intent to prepare an Environmental Impact Statement, which included, among other things, two public scoping sessions in Puerto Rico held on November 18, 2024 in accordance with the National Environmental Policy Act.
12 Results of Operations – Three Months Ended March 31, 2025 compared to Three Months Ended December 31, 2024 and Three Months Ended March 31, 2024 Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets. Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non- GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business. The tables below present our segment information for the three months ended March 31, 2025, December 31, 2024 and March 31, 2024: Three Months Ended March 31, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 431,927 $ 38,609 $ 470,536 $ — $ 470,536 Cost of sales(1) 302,377 — 302,377 — 302,377 Vessel operating expenses(3) — 7,176 7,176 — 7,176 Operations and maintenance(3) 54,957 — 54,957 — 54,957 Segment Operating Margin $ 74,593 $ 31,433 $ 106,026 $ — $ 106,026 Three Months Ended March 31, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 52,969 Depreciation and amortization 53,057 Consolidated Segment Operating Margin (Non-GAAP) $ 106,026
13 Three Months Ended December 31, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other(2) Consolidated Total revenues $ 528,908 $ 42,363 $ 571,271 $ 107,727 $ 678,998 Cost of sales(1) 288,398 — 288,398 — 288,398 Vessel operating expenses(3) — 8,219 8,219 — 8,219 Operations and maintenance(3) 34,411 — 34,411 — 34,411 Segment Operating Margin $ 206,099 $ 34,144 $ 240,243 $ 107,727 $ 347,970 Three Months Ended December 31, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 309,224 Depreciation and amortization 38,746 Consolidated Segment Operating Margin (Non-GAAP) $ 347,970 Three Months Ended March 31, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 647,737 $ 42,584 $ 690,321 $ — $ 690,321 Cost of sales(1) 229,117 — 229,117 — 229,117 Vessel operating expenses(3) — 8,396 8,396 — 8,396 Operations and maintenance(3) 68,548 — 68,548 — 68,548 Segment Operating Margin $ 350,072 $ 34,188 $ 384,260 $ — $ 384,260 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 (1) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive (Loss) Income. (2) For the three months ended December 31, 2024, Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $107.7 million which were recognized during the fourth quarter of 2024. (3) Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP.
14 Terminals and Infrastructure Segment Three Months Ended (in thousands of $) March 31, 2025 December 31, 2024 Change March 31, 2024 Change Total revenues $ 431,927 $ 528,908 $ (96,981) $ 647,737 $ (215,810) Cost of sales (exclusive of depreciation and amortization) 302,377 288,398 13,979 229,117 73,260 Operations and maintenance 54,957 34,411 20,546 68,548 (13,591) Segment Operating Margin $ 74,593 $ 206,099 $ (131,506) $ 350,072 $ (275,479) Total revenue Total revenue for the Terminals and Infrastructure Segment decreased by $97.0 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024, and total revenue for the Terminals and Infrastructure Segment decreased by $215.8 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The decrease in revenue in the first quarter of 2025 when compared to the fourth quarter of 2024 was primarily attributable to contract novation income recognized during the three months ended December 31, 2024, and a decrease in volumes delivered to downstream customers. • The Company novated an LNG supply contract to a customer, recognizing $235.6 million within segment revenue in the fourth quarter of 2024. No such contract novation income was recognized during the three months ended March 31, 2025. • Volumes delivered to downstream terminal customers decreased from 18.4 TBtu in the fourth quarter of 2024 to 13.8 TBtu in the first quarter of 2025 due to maintenance at our Old Harbour and San Juan facilities. • We recognized $182.7 million of revenue from cargos sales for the three months ended March 31, 2025 as compared to $91.9 million for the three months ended December 31, 2024. • The average Henry Hub index pricing used to invoice our downstream customers increased by 31% for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The decrease in revenue in the first quarter of 2025 when compared to the first quarter of 2024 was primarily attributable to the termination of our grid stabilization project in the first quarter of 2024. The decrease in revenue was partially offset by higher Henry Hub index pricing and cargo sales. • For the three months ended March 31, 2025, volumes delivered to downstream customers were 13.8 TBtu as compared to 22.0 TBtu for the three months ended March 31, 2024 due to maintenance at our Old Harbour and San Juan facilities. • The higher volumes in the first quarter of 2024 was primarily attributable to additional sales in Puerto Rico from our grid stabilization project. Our customer terminated the grid stabilization project in the first quarter of 2024, but we continue to sell volumes into these power plants under an island-wide gas sale agreement signed with PREPA. The agreement is set to expire in June 2025, and we are in active discussions with PREPA for an extension. • Revenue from cargos sales was $182.7 million for the three months ended March 31, 2025. The Company had no cargo sales for the three months ended March 31, 2024 as we were able to utilize all volumes under our supply contracts in our downstream terminal operations.
15 • The average Henry Hub index pricing used to invoice our downstream customers increased by 63% for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. Cost of sales Cost of sales includes the procurement of feed gas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. We source LNG and natural gas from third parties and our own liquefaction facilities, including our first Fast LNG unit which was placed into service in the fourth quarter of 2024. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our liquefaction facilities are also included in Cost of sales. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide operations and maintenance services to PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue. Cost of sales increased by $14.0 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. • In the first quarter of 2025, we incurred $103.8 million of cargo sales costs as compared to $53.9 million for the three months ended December 31, 2024. • We delivered 25% lower volumes to our customers in the first quarter of 2025, decreasing the cost of LNG to supply our downstream customers by $27.7 million. The weighted average cost of gas purchased increased from $8.75 per MMBtu for the three months ended December 31, 2024 to $9.57 per MMBtu for the three months ended March 31, 2025. Cost of sales increased by $73.3 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024, which was attributable to the following: • In the first quarter of 2025, we incurred $103.8 million of cargo sales costs. In the first quarter of 2024, we did not have any cargo sales and we delivered higher volumes to our downstream terminal customers. • We delivered 37% lower volumes to our customers during the first quarter of 2025. Though we delivered lower volumes to our downstream customers, the cost of gas purchased increased significantly from $6.96 per MMBtu in the first quarter of 2024 to $9.57 per MMBtu in the first quarter of 2025. In addition, the Henry Hub pricing also increased by 63% from March 2024 to March 2025. • Vessel costs increased by $12.3 million, for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024, principally due to lower vessel utilization in the first quarter of 2025. The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2025 and December 31, 2024 was $8.73 per MMBtu and $6.90 per MMBtu, respectively. Operations and maintenance Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance increased by $20.5 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. We placed our first Fast LNG project and Santa Catarina Facility into service in
16 the fourth quarter of 2024. The increase was primarily attributable to payroll, maintenance, logistics and other costs incurred for operating these new facilities placed into service in 2024. Operations and maintenance decreased by $13.6 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. In the first quarter of 2024, our grid stabilization contract was terminated and assets related to the project were sold to PREPA. The decrease in costs during the three months ended March 31, 2025 are primarily due to lease and other maintenance costs that were no longer incurred for the sold assets, partially offset by the increased costs incurred for new facilities placed into service in 2024. Ships Segment Three Months Ended, (in thousands of $) March 31, 2025 December 31, 2024 Change March 31, 2024 Change Total revenues $ 38,609 $ 42,363 $ (3,754) $ 42,584 $ (3,975) Vessel operating expenses 7,176 8,219 (1,043) 8,396 (1,220) Segment Operating Margin $ 31,433 $ 34,144 $ (2,711) $ 34,188 $ (2,755) 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 March 31, 2025, three vessels included in the Energos Formation Transaction were leased to customers under long-term arrangements and are included in this segment. Total revenue Total revenue for the Ships segment decreased $3.8 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. Total revenue for the Ships segment decreased $4.0 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of certain vessels included in the transaction, and as such, we continue to recognize revenue from the charter of these vessels to third parties. The third-party charter of the vessel Energos Maria ended during the fourth quarter of 2024, and we are using the vessel at our terminal operations, resulting in a decrease in the vessel charter revenue. Vessel operating expenses Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, and management fees. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter. Vessel operating expenses decreased $1.0 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. Vessel operating expenses decreased $1.2 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. As discussed above, the vessel operating costs were lower as the vessel Maria has been utilized for our terminal operations.
17 Other operating results Three Months Ended, (in thousands of $) March 31, 2025 December 31, 2024 Change March 31, 2024 Change Selling, general and administrative $ 59,271 $ 61,800 $ (2,529) $ 70,754 $ (11,483) Transaction and integration costs 11,931 5,994 5,937 1,371 10,560 Depreciation and amortization 53,057 38,746 14,311 50,491 2,566 Asset impairment expense 246 10,738 (10,492) — 246 Loss on sale of assets, net — 422 (422) 77,140 (77,140) Total operating expenses 124,505 117,700 6,805 199,756 (75,251) Operating income (18,479) 230,270 (248,749) 184,504 (202,983) Interest expense 213,694 99,527 114,167 77,344 136,350 Other expense (income), net (63,937) 52,447 (116,384) 19,112 (83,049) Loss on extinguishment of debt, net 467 260,309 (259,842) 9,754 (9,287) (Loss) income before income taxes (168,703) (182,013) 13,310 78,294 (246,997) Tax provision (benefit) 28,670 41,497 (12,827) 21,624 7,046 Net income $ (197,373) $ (223,510) $ 26,137 $ 56,670 $ (254,043) 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 decreased by $2.5 million for the three months ended March 31, 2025, compared to the three months ended December 31, 2024. The decrease was mostly driven by the reversal of previously recorded share- based compensation expense due to forfeitures during the quarter ended March 31, 2025. Selling, general and administrative decreased by $11.5 million for three months ended March 31, 2025 as compared to the three months ended March 31, 2024. During the quarter ended March 31, 2024, the Company recognized an additional allowance for uncollectible receivables of $11.6 million. The allowance reduces outstanding receivables for certain customers to reflect the amount that the Company expects to receive. No significant allowance was recognized during the three months ended March 31, 2025. We recognized $5.2 million of share-based compensation costs associated with RSUs issued for the three months ended March 31, 2024. Due to forfeitures during the quarter ended March 31, 2025, the Company recognized a reversal of previously recorded share-based compensation expense which significantly lowered the expense for the period. The decreases above were partially offset by higher screening costs incurred for our development projects during the first quarter of 2025. Transaction and integration costs The transaction and integration costs of $11.9 million and $6.0 million during the three months ended March 31, 2025 and December 31, 2024, respectively, primarily relate to legal fees and other third party costs incurred by the Company in connection with amendments to credit agreements. During the first quarter of 2025, we paid the Barcarena Debentures and amended the Term Loan B Credit Agreement, and $6.1 million of third party costs associated with these modifications were recognized as Transaction and integration costs. During the first quarter of 2025, we also incurred $3.9 million of legal fees related to the sale of our Jamaica Business.
18 Depreciation and amortization Depreciation and amortization increased by $14.3 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The increase is mainly due to depreciation expense on the Fast LNG project and the Santa Catarina Facility that were placed into service during the fourth quarter of 2024. Depreciation and amortization expense increased by $2.6 million for the three months ended March 31, 2025 as compared to the three months ended March 31, 2024. The increase in depreciation expense resulting from the Fast LNG project and the Santa Catarina Facility being placed into service in December 2024, was partially offset by a reduction due to the sale of certain turbines and equipment to PREPA in March 2024. Asset impairment expense For the three months ended March 31, 2025 and December 31, 2024, the Company recognized an impairment of $0.2 million and $10.7 million related to the sale of the Miami Facility. There was no impairment of assets during the three months ended March 31, 2024. Loss on sale of assets, net The Company had no significant asset sales during the first quarter of 2025 and fourth quarter of 2024. During the three months ended March 31, 2024, the Company recognized a loss of $77.5 million from the sale of turbines and related equipment to the PREPA. Interest expense Interest expense increased by $114.2 million for the three months ended March 31, 2025 as compared to the three months ended December 31, 2024. The increase was primarily due to lower interest capitalized of $74.1 million during the quarter ended March 31, 2025 compared to $139.5 million during the quarter ended December 31, 2024. We placed the Fast LNG project and Santa Catarina Facility into service during the quarter ended December 31, 2024, and are no longer capitalizing interest towards these projects. In addition, we have incurred increased borrowing costs under the New 2029 Notes (as defined in our Annual Report) and the Brazil Financing Notes. We also amended our Term Loan A Credit Agreement and recognized an interest expense of $18.1 million relating to origination, structuring and other fees, which were previously capitalized. Interest expense increased by $136.4 million for the three months ended March 31, 2025, as compared to the three months ended March 31, 2024. The increase was primarily due to an increase in total principal outstanding due to additional principal balance outstanding. The total principal balance on outstanding facilities was $9.4 billion as of March 31, 2025 as compared to total outstanding debt of $7.2 billion as of March 31, 2024. We also capitalized lower interest expense of $74.1 million during the first quarter of 2025 compared to $104.2 million during the first quarter of 2024 as the Fast LNG project and Santa Catarina Facility were placed into service towards the end of 2024. In addition, we recognized an interest expense of $18.1 million upon amendment of our Term Loan A credit agreement.
19 Other expense (income), net Other (income) expense, net was $(63.9) million, $52.4 million and $19.1 million for the three months ended March 31, 2025, December 31, 2024 and March 31, 2024, respectively. The Other income recognized in the three months ended March 31, 2025 was primarily due to foreign currency remeasurement gains in the first quarter of 2025, supported by the appreciation of the Brazilian real against the U.S. dollar. Other expense, net recognized in the three months ended December 31, 2024 and March 31, 2024 was primarily comprised of foreign currency loss due to remeasurement of U.S. dollar denominated debt in our Brazil subsidiary. The losses were partly offset by interest income, and realized and unrealized gains on foreign currency derivative contracts. Loss on extinguishment of debt During the three months ended March 31, 2025, we recognized $0.5 million of loss on extinguishment of debt related to the repayment of the Barcarena Debentures. During the fourth quarter of 2024, we repaid all of the 2025 Notes and a portion of the 2026 Notes and 2029 Notes, and recognized as a loss on extinguishment of debt totaling $235.4 million. During the three months ended March 31, 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes. We also recognized a premium over the repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes. Tax provision We recognized a tax provision for the three months ended March 31, 2025 of $28.7 million compared to a tax provision of $41.5 million for the three months ended December 31, 2024 and a tax provision of $21.6 million for the three months ended March 31, 2024. The tax provision recognized in the first quarter of 2025 was primarily driven by the expected gain from sale of the Jamaica Business, inclusion of foreign earnings related to our Brazil operations included in the effective tax rate, and increase in valuation allowance in the U.S. operations. 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 results of operations include our Jamaica Business. In May 2025, we completed the sale of our Jamaica Business, and after this point, we will no longer include the results of operations of our Montego Bay Facility and Old Harbour Facility in our financial statements. • Our future results of operations will include the cost of operating our Fast LNG solution that were not included in our historical financial statements. We placed our first Fast LNG project into service in the fourth quarter of 2024. This project represents our largest ever capital project and placing the asset into service from an accounting perspective will significantly increase the depreciation recognized in future periods; such depreciation will also impact the cost of LNG delivered from the FLNG facility. We also expect interest expense to increase as we are no longer able to capitalize borrowing costs associated with this development. While the asset is in service from an accounting perspective, we will continue to optimize the asset to enhance liquefaction capacity. Such costs that enhance the asset will be capitalized on our Condensed Consolidated Balance Sheets. • Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the three months ended March 31, 2025 include our Montego Bay
20 Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant and certain industrial end-users. We placed the Santa Catarina Facility into service in the fourth quarter of 2024. We have also completed construction of our Barcarena Facility and are in the final stages of commissioning this facility. We are also continuing to develop our Barcarena Power Plant, PortoCem Power Plant, Puerto Sandino Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects. In the first quarter of 2024, our grid stabilization contract was terminated and related assets were sold to PREPA. Under our new island-wide gas sale agreement with PREPA, we continue to supply gas to these power generation assets. In March 2025, the agreement was amended to extend the term by 100 days to June 2025.
21 Liquidity and Capital Resources We have made significant progress in extending the maturities of our long-term debt, and we continue to explore asset sales, settlement of claims and other strategic transactions (the "Strategic Transactions") that seek to optimize the value of our portfolio while providing additional liquidity and cash flow. As part of preparing the financial statements, under ASC 205-40, when first assessing whether substantial doubt is raised about the entity’s ability to continue as a going concern, management cannot consider the potential mitigating effects of its plans that have not been fully implemented at the assessment date. Under this guidance, we are required to exclude the effects of the Strategic Transactions from our forecast, and as such, we concluded that our current liquidity and forecasted cash flows from operations are not sufficient to support, in full, obligations as they become due. We have approved a plan to alleviate liquidity risk, however, our assessment of whether we will have sufficient liquidity to meet our obligations as they become due over the next twelve months from the date that the consolidated financial statements will be issued is in progress. Additionally, we expect our current working capital position to improve based on the following: (1) expected cash flows generated from potential new gas sale agreements and volume growth in Puerto Rico, Mexico and Brazil; (2) sales of our own LNG generated by our first deployed Fast LNG unit; (3) continued proceeds from Strategic Transactions; and (4) our relationships with certain significant vendors, including vendors constructing our Fast LNG assets, have allowed us to extend our payment terms to better align with the expected completion of our first Fast LNG project. However, there are inherent uncertainties, as the execution of the Strategic Transactions are outside of management’s control and therefore there are no assurances that these transactions will be executed. Furthermore, there are inherent risks with the Company’s ability to continue to implement plans in future periods that will support its liquidity position, such as its ability to further extend the terms of vendor payments and other obligations. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions. The terms and conditions of our indebtedness include restrictive covenants that limit our ability to operate our business, incur or refinance our debt, engage in certain transactions, and require us to maintain certain financial ratios, among others, any of which may limit our ability to finance future operations and capital needs, react to changes in our business and in the economy generally, and to pursue business opportunities and activities. Following the completion of the Refinancing Transactions in the fourth quarter of 2024, our ability to undertake these activities, including our ability to incur or refinance our debt, is further limited. Furthermore, the restrictions contemplated by certain of the amendments to our Revolving Facility require proceeds of certain asset sales to be used to pay down existing indebtedness. From time to time, we may seek to repay, refinance or restructure all or a portion of our debt or to repurchase our outstanding debt through, as applicable, tender offers, redemptions, exchange offers, open market purchases, privately negotiated transactions or otherwise. Such transactions, if any, will depend on a number of factors, including prevailing market conditions, our liquidity requirements and contractual requirements (including compliance with the terms of our debt agreements), among other factors. Our remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, is approximately $881 million and includes remaining expenditures to complete our first Fast LNG project and our onshore liquefaction project at Altamira, as well as committed expenditures necessary to complete the Puerto Sandino Facility, Barcarena and PortoCem Power Plants. This does not include any capital expenditures related to Klondike. We have secured financing commitments to continue to develop our Barcarena Power Plant and PortoCem Power Plant, which represents approximately $294 million of our upcoming committed capital expenditures. We expect fully completed Fast LNG units to cost between $1.0 billion and $2.0 billion per unit on average. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to construct the Fast LNG units allow us to closely control the timing of our spending and construction schedules so that we can complete each project in time frames to meet our business needs. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.
22 As of March 31, 2025, we have spent approximately $128.6 million to develop the Pennsylvania Facility. Approximately $22.5 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. 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, 2025: (in thousands of $) Total Less than Year 1 Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 14,622,243 $ 855,852 $ 3,734,342 $ 6,394,222 $ 3,637,827 Purchase obligations 20,199,235 513,093 1,188,305 1,691,977 16,805,860 Lease obligations 782,069 121,595 223,749 194,417 242,308 Total $ 35,603,547 $ 1,490,540 $ 5,146,396 $ 8,280,616 $ 20,685,995 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, 2025. A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. 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, 2025. We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant and PortoCem Power Plant. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.
23 Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, and a land lease. Cash Flows The following table summarizes the changes to our cash flows for the three months ended March 31, 2025 and 2024, respectively: Three Months Ended March 31, (in thousands of $) 2025 2024 Change Cash flows from: Operating activities $ (31,705) $ 70,050 $ (101,755) Investing activities (335,915) (219,780) (116,135) Financing activities 204,456 157,617 46,839 Net (decrease) increase in cash, cash equivalents, and restricted cash $ (163,164) $ 7,887 $ (171,051) Cash (used in) / provided by operating activities Our cash flow used in operating activities was $31.7 million for the three months ended March 31, 2025, which increased by $101.8 million from cash provided by operating activities of $70.1 million for the three months ended March 31, 2024. Our net loss for the three months ended March 31, 2025, when adjusted for non-cash items, increased by $358.5 million from the three months ended March 31, 2024. The increase in net loss when adjusted for non-cash items was offset by increases to accounts payable and other changes in working capital. Cash used in investing activities Our cash flow used in investing activities was $335.9 million for the three months ended March 31, 2025, which increased by $116.1 million from cash used in investing activities of $219.8 million for the three months ended March 31, 2024. Cash flows from investing activities during the three months ended March 31, 2025 were used primarily for continued development of our onshore FLNG project and the construction of the PortoCem Power Plant. Cash outflows for investing activities during the three months ended March 31, 2024 were used primarily for the continued development of our Fast LNG project and construction of our Barcarena Power Plant. Cash outflows were offset by proceeds of $306.6 million from the sale of turbines and related equipment to PREPA, $136.4 million from the sale of our equity method investment in Energos and $22.4 million from the sale of the Mazo. Cash provided by financing activities Our cash flow provided by financing activities was $204.5 million for the three months ended March 31, 2025, which increased by $46.8 million from cash provided by financing activities of $157.6 million for the three months ended March 31, 2024. During the three months ended March 31, 2025 we had total borrowings of $943.6 million, with such borrowings primarily used to fund continued development of the onshore FLNG project and for other corporate expenses. Such borrowings were also used to repay the Barcarena Debentures in full. We also repaid our Revolving Facility by $275.0 million. In the first quarter of 2024 we issued $750.0 million of 2029 Notes with such borrowings primarily used to repay $375.0 million of the 2025 Notes and repay a portion of our outstanding balance on the Revolving Facility. In advance of the sale of turbines to PREPA, we also repaid the Equipment Notes in full. Subsequently, we utilized our Revolving
24 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. Under certain intercompany agreements entered into in conjunction with the Refinancing Transactions completed in the fourth quarter of 2024, New Fortress Energy Inc. is no longer permitted to pay dividends to shareholders. Long-Term Debt The terms of our debt instruments and associated obligations have been described in our Annual Report. There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below. Term Loan B Credit Agreement In March 2025, we entered into an amendment to the Term Loan B Credit Agreement. Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425.0 million, which increased the total outstanding principal amount to $1,272.4 million ("Term Loan B"). The incremental term loans were issued at a discount, and we received proceeds, net of discount, of $391.0 million. Net proceeds will be used primarily to fund capital expenditures of the onshore FLNG project, and for other corporate expenses. The incremental term loans are subject to the same maturity date as the term loans under the original agreement. Quarterly principal payments of approximately $3.2 million are required beginning June 2025. The Term Loan B is secured by the same collateral as that secured the term loans under the original agreement. The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the amendment) plus 5.5%. We may prepay the Term Loan B at its option subject to prepayment premiums until March 10, 2028 and customary break funding costs. We are required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances and with our Excess Cash Flow (as defined in the amendment), in each case subject to certain exceptions and thresholds. We must comply with the same covenant requirements as those under the original agreement. The Term Loan B Credit Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B Credit Agreement. Term Loan A Credit Agreement In March 2025, we entered into an amendment to the Term Loan A Credit Agreement. Pursuant to the amendment, the future borrowing commitments are reduced to zero, eliminating the potential for future borrowings under the Term Loan A Credit Agreement. The Term Loan A Credit Agreement contains usual and customary representations, warranties and affirmative and negative covenants for financings of this type, including certain representations and warranties related to the Onshore Altamira Project. The Term Loan A Credit Agreement includes certain other covenants related solely to the Onshore Altamira Project, including limitations on capital expenditures, restrictions on additional accounts, and restrictions on amendments or termination of certain material documents related to the Onshore Altamira Project. We must also comply with certain financial covenants consistent with those under the Revolving Facility, including Debt to EBITDA Ratio and minimum consolidated liquidity.
25 Brazil Financing Notes In February 2025, one of our consolidated subsidiaries entered into an agreement to issue up to $350.0 million aggregate principal amount of 15.0% Senior Secured Notes due 2029 (the “Brazil Financing Notes”) at a purchase price of 97.75% of par. The Brazil Financing Notes mature on August 30, 2029; the principal is due in full on the maturity date. Interest is payable quarterly in arrears beginning on June 30, 2025, and for the first 30 months that the Brazil Financing Notes are outstanding, interest due can be paid in kind and added to the principal amount. A portion of the proceeds from the issuance of the Brazil Financing Notes of $208.7 million was used to repay the Barcarena Debentures in full. The Brazil Financing Notes contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Brazil Financing Notes. 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, 2025, there have been no significant changes to our critical accounting estimates since our Annual Report.