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, 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. 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 Liquidity and going concern As part of preparing the condensed consolidated financial statements included in this Quarterly Report, we have evaluated whether conditions exist that give rise to substantial doubt as to the ability of the Company to continue as a going concern, considering the following: • We recognized operating losses and negative operating cash flows during each of the first three quarters of 2025, with this decline in earnings accelerating in the second quarter of 2025. Our forecasted cash flows are expected to be impacted by, among other things, reduced earnings following the sale of the Jamaica Business and increased interest expense. • In November 2025, we entered into amendments to the Revolving Credit Agreement, the Letter of Credit Agreement and the Term Loan A Credit Agreement (each as defined in the Annual Report) to, among other things, (a) in the case of the Letter of Credit Facility (as defined in the Annual Report), extend the maturity date of the facility to March 31, 2026, (b) provide for a covenant holiday with respect to (x) the consolidated first lien debt ratio and fixed charge coverage ratio covenants contained therein for the fiscal quarter ended September 30, 2025 (or in the case of the Letter of Credit Facility, also provide for a covenant holiday for the fiscal quarter ending December 31, 2025) and (y) the minimum liquidity requirement contained therein for the fiscal quarter ended December 31, 2025 (or in the case of the Letter of Credit Facility, remove the fiscal quarter minimum liquidity test altogether), (c) remove certain flexibility we had to pay dividends and other distributions, and (d) restrict our ability to make payments of principal or interest accruing on certain outstanding indebtedness, including the November 17, 2025 interest payment on the New 2029 Notes (as defined in the Annual Report). • We also do not expect to be in compliance with the consolidated first lien debt ratio and fixed charge coverage ratio covenants for the fiscal quarter ending December 31, 2025 under the Revolving Credit Agreement and the Term Loan A Credit Agreement. If we do not enter into an agreement with the lenders under the Revolving Facility (as defined in the Annual Report) and the Term Loan A Credit Agreement to provide for a covenant holiday or other covenant relief for the fiscal quarter ending December 31, 2025, by the time we furnish to the administrative agents for the Revolving Facility and Term Loan A Credit Agreement audited financial statements for such fiscal year, the lenders would have the right to accelerate the repayment of the outstanding principal under the Revolving Facility and Term Loan A Credit Agreement. If the lenders choose to exercise such rights 41 Table of Contents under those facilities, substantially all of our outstanding indebtedness could be accelerated, and we would not have sufficient liquidity or capital resources to satisfy its outstanding principal obligations. • NFE Financing LLC, a subsidiary of the Company (the “New 2029 Notes Issuer”), did not make the interest payment of $163.8 million due to holders of the New 2029 Notes on November 17, 2025. An event of default under the indenture governing the New 2029 Notes will arise on November 20, 2025, when the contractual grace period for interest payments on such notes expires. On November 18, 2025, the Company and certain of its subsidiaries, including the New 2029 Notes Issuer, entered into a forbearance agreement with the beneficial holders of greater than 70% of the New 2029 Notes (the “New 2029 Notes Forbearance Agreement”), pursuant to which such beneficial holders agreed to forbear from accelerating or exercising remedies in respect of such event of default. Unless earlier terminated, the New 2029 Notes Forbearance Agreement will terminate on December 15, 2025. Upon the termination of the New 2029 Notes Forbearance Agreement, if a further forbearance or debt restructuring is not agreed to, the holders of the New 2029 Notes could accelerate the outstanding principal balance of the New 2029 Notes, in which case substantially all of our other outstanding debt would become payable on demand. The New 2029 Notes Forbearance Agreement contains conditions, covenants, termination rights and other provisions customary for forbearance agreements of that type. • We were required to provide a $79.1 million bank guarantee to holders of the PortoCem Debentures on or before August 17, 2025; this guarantee was not provided by the deadline, and as a result, a majority of debenture holders had the right to call for a meeting of holders and declare an event of early maturity. On October 11, 2025, the debenture holders unanimously permanently waived their ability to declare an early maturity event due to the failure to provide the bank guarantee. The remaining $79.1 million bank guarantee is now due on or before May 10, 2026, and if this guarantee or an equivalent amount of equity contribution to the project company is not made by this date, an automatic event of default will exist under the amended debenture agreement. We are discussing providing this bank guarantee with our creditors under new credit arrangements, and should additional financing or credit capacity be provided under new credit agreements, we intend to comply with the requirements of the waiver. However, based on our current liquidity, we determined that it is not currently probable that the bank guarantee can be provided, absent an agreement with our existing creditors or new lenders. If such automatic early maturity event were to occur, substantially all of our outstanding indebtedness would be payable on demand. • Additionally, we have $510.9 million aggregate principal amount outstanding as of September 30, 2025 under our 2026 Notes, which mature on September 30, 2026. If more than $100 million of the 2026 Notes remain outstanding 91 days prior to this maturity date (the "Springing Maturity Date"), the outstanding principal of $2.7 billion under the New 2029 Notes becomes due. If any of the 2026 Notes remains outstanding on the Springing Maturity Date, the outstanding balance under the Revolving Facility becomes due. As of September 30, 2025, the Revolving Facility was fully drawn with $660.4 million in revolving loans and $69.5 million in letters of credit. Additionally, if any of the 2026 Notes remain outstanding on July 31, 2026, the outstanding principal under the Term Loan B becomes due. Also, if any of the 2026 Notes remain outstanding 60 days prior to the maturity date of the 2026 Notes, the outstanding principal under the Term Loan A Credit Agreement becomes due. As of September 30, 2025, there was $295.0 million outstanding under the Term Loan A Credit Agreement and $1.27 billion outstanding under the Term Loan B. As such, management has concluded that our current liquidity and forecasted cash flows from operations are not probable to be sufficient to support, in full, its obligations as they become due, and there is substantial doubt as to the Company’s ability to continue as a going concern. Should we not be in compliance with covenants in the Revolving Credit Agreement and Term Loan A Credit Agreement in the future, we will engage in negotiations with these lenders to obtain a waiver to avoid acceleration of outstanding balances. Additionally, should the Company not provide the additional bank guarantee to holders of the PortoCem Debentures by the required date, we will engage with these holders to avoid an event of early maturity. We have also initiated a process to evaluate strategic alternatives and have retained a financial advisor to assist in this evaluation. We, along with our advisors, are considering all options available, including asset sales, capital raising, debt amendments and refinancing transactions, or, other strategic transactions that seek to provide additional liquidity and relief from acceleration under its debt agreements. We are activity managing our liquidity as we continue this evaluation with our advisors, and as part of this process, we are negotiating payment plans with significant vendors, most significantly the owners under our vessel charters. If unsuccessful in these strategic alternatives, we may be required or compelled to pursue additional restructuring initiatives to preserve value and optionality, including possible out of court restructurings, or in-court relief, in the U.K. or the U.S., which could have a material and adverse impact on stockholders. There are inherent 42 Table of Contents uncertainties as the outcome of these negotiations and potential transactions described above are outside management’s control, and therefore there are no assurances that management will be successful in these negotiations and that any of these potential transactions will occur. In addition, there can be no assurances that these transactions will sufficiently improve our liquidity or that we will otherwise realize the anticipated benefits. We are also evaluating strategies to obtain the required additional funding for our future operations, including the following transactions that are excluded from our forecast, among other things: (1) settlement of our claims resulting from the termination of the emergency power services contract in Puerto Rico in the first quarter of 2024, (2) realization of up to $110.0 million in proceeds from the modification of Genera’s Operation and Maintenance Agreement; (3) receipt of proceeds from the sale of the Jamaica Business that are currently in escrow; (4) expected cash flows from new business in Puerto Rico and Brazil. Business 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 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 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. On May 14, 2025, we completed the sale of our Jamaica business, including operations at the LNG import terminal in Montego Bay, the offshore floating storage and regasification terminal in Old Harbour and the 150 megawatt Combined Heat and Power Plant in Clarendon, along with the associated infrastructure (the "Jamaica Business") receiving net cash proceeds of approximately $678 million, with additional $99 million proceeds held in escrow and to be returned to the Company based on the terms of the sale agreement. Our Current Operations – Terminals and Infrastructure Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including 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. 43 Table of Contents 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 dual-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. In March 2024, 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 expired in March 2025. During 2025, the Company and PREPA agreed to a series of short-term extensions of the gas supply agreement while working towards a long-term solution that is in the best interests of both parties and achieves our mutual goal of sustained, efficient power generation for Puerto Rico. In September 2025, both parties reached agreement on contract terms for the long-term supply of LNG to Puerto Rico, which the Financial Oversight and Management Board of Puerto Rico ("FOMB") then made further comments. The Parties remain in negotiations to finalize the new gas supply agreement and submit it for review and approval by the FOMB. The current gas supply agreement is extended on a weekly basis until the new gas supply agreement is approved by the FOMB. There can be no assurances that the long-term gas sale agreement will be executed, and to the extent the Company is not able to execute such an agreement, the Company's future results of operations could be adversely impacted and the impact could be material. 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. The service period under the contract commenced on July 1, 2023, and we receive an annual management fee for the services provided. 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 third quarter of 2024, we executed an amendment to the gas sales agreement to multiple CFE power generation facilities in Baja California Sur on a take-or-pay basis that extended the term to ten years from November 3, 2024, and amended the annual minimum volumes. 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 São Paulo, within the city limits of Lins. We expect to participate in the power auctions anticipated to occur in 2026 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. 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) 44 Table of Contents additional LNG supply contracts expected to commence in 2027. Our first FLNG facility began to produce LNG in July 2024, and we expect to generate up to 70 TBtu annually from this facility. When expected production from FLNG is combined with our commitments to purchase and receive physical delivery of LNG volumes, we expect to have sufficient supply for 100% of our committed volumes for each of our downstream terminals inclusive of our San Juan Facility, La Paz Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to commence in 2027 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 (“Barcarena Facility”) and power plants located in Pará, Brazil; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal and power plant in Ireland (“Ireland Facility”), our first green hydrogen project ("ZeroPark I") and Klondike Digital Infrastructure, our power and data center infrastructure business ("Klondike"). We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations. The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects. We describe each of our current development projects below. Fast LNG 45 Table of Contents 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 are considering a plan 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. 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 and reach commercial operation 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. Puerto Sandino Facility 46 Table of Contents 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. 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 2028. In the third quarter of 2023, An Bord Pleanála ("ABP"), Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We challenged this decision, and in September 2024, the High Court of Ireland ruled that ABP did not have appropriate grounds for the denial of our p ermit. In March 2025, ABP 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 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. On July 4, 2025, the Tax Act of 2025 was enacted in the U.S. The Tax Act of 2025 introduces multiple tax law and other legislative changes, including the rules and timing for the IRA 45V production tax credit. We continue to evaluate the impact of the tax credit in relation to the project. 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. 47 Table of Contents 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. 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 forthcoming. In concert with our collaboration with the USCG regarding our new operational plans, we withdrew our appeal on February 14, 2025. On October 25, 2024, FERC issued a notice of intent to prepare an Environmental Impact Statement, which included, among other things, two public scoping sessions in Puerto Rico held on November 18, 2024 in accordance with the National Environmental Policy Act. Results of Operations – Three Months Ended September 30, 2025 compared to Three Months Ended June 30, 2025 and Nine Months Ended September 30, 2025 compared to Nine Months Ended September 30, 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 48 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 September 30, 2025 and June 30, 2025, and for the nine months ended September 30, 2025 and September 30, 2024: Three Months Ended September 30, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 301,765 $ 25,602 $ 327,367 $ — $ 327,367 Cost of sales (1) 196,908 — 196,908 — 196,908 Vessel operating expenses (2) 1,940 5,357 7,297 — 7,297 Operations and maintenance (2) 58,520 — 58,520 — 58,520 Segment Operating Margin $ 44,397 $ 20,245 $ 64,642 $ — $ 64,642 Three Months Ended September 30, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 14,168 Depreciation and amortization 50,474 Consolidated Segment Operating Margin (Non-GAAP) $ 64,642 Three Months Ended June 30, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (2) Consolidated Total revenues $ 263,236 $ 38,456 $ 301,692 $ — $ 301,692 Cost of sales (1) 208,852 — 208,852 — 208,852 Vessel operating expenses (2) 1,765 6,291 8,056 — 8,056 Operations and maintenance (2) 59,817 — 59,817 — 59,817 Segment Operating Margin $ (7,198) $ 32,165 $ 24,967 $ — $ 24,967 49 Table of Contents Three Months Ended June 30, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ (27,903) Depreciation and amortization 52,870 Consolidated Segment Operating Margin (Non-GAAP) $ 24,967 Nine Months Ended September 30, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 996,928 $ 102,667 $ 1,099,595 $ — $ 1,099,595 Cost of sales (1) 708,137 — 708,137 — 708,137 Vessel operating expenses (2) 3,705 18,824 22,529 — 22,529 Operations and maintenance (2) 173,294 — 173,294 — 173,294 Segment Operating Margin $ 111,792 $ 83,843 $ 195,635 $ — $ 195,635 Nine Months Ended September 30, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 39,234 Depreciation and amortization 156,401 Consolidated Segment Operating Margin (Non-GAAP) $ 195,635 Nine Months Ended September 30, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 1,515,365 $ 128,224 $ 1,643,589 $ 42,273 $ 1,685,862 Cost of sales (1) 776,269 — 776,269 — 776,269 Vessel operating expenses (2) — 25,153 25,153 — 25,153 Operations and maintenance (2) 139,902 — 139,902 — 139,902 Deferred earnings from contracted sales (3) 150,000 — 150,000 (150,000) — Segment Operating Margin $ 749,194 $ 103,071 $ 852,265 $ (107,727) $ 744,538 Nine Months Ended September 30, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 621,270 Depreciation and amortization 123,268 Consolidated Segment Operating Margin (Non-GAAP) $ 744,538 (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) 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. 50 Table of Contents (3) Deferred earnings from contracted sales represent forward sales transactions that were contracted in the second quarter of 2024 and prepayment for these sales was received. Revenue has been recognized in the Condensed Consolidated Statements of Operations and Comprehensive (Loss) Income during the third and fourth quarters of 2024. Terminals and Infrastructure Segment Three Months Ended (in thousands of $) September 30, 2025 June 30, 2025 Change Total revenues $ 301,765 $ 263,236 $ 38,529 Cost of sales (exclusive of depreciation and amortization) 196,908 208,852 (11,944) Vessel operating expenses 1,940 1,765 175 Operations and maintenance 58,520 59,817 (1,297) Segment Operating Margin $ 44,397 $ (7,198) $ 51,595 Nine Months Ended, (in thousands of $) September 30, 2025 September 30, 2024 Change Total revenues $ 996,928 $ 1,515,365 $ (518,437) Cost of sales (exclusive of depreciation and amortization) 708,137 776,269 (68,132) Vessel operating expenses 3,705 — 3,705 Operations and maintenance 173,294 139,902 33,392 Deferred earnings from contracted sales — 150,000 (150,000) Segment Operating Margin $ 111,792 $ 749,194 $ (637,402) Total revenue Total revenue for the Terminals and Infrastructure Segment increased by $38.5 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025, and total revenue for the Terminals and Infrastructure Segment decreased by $518.4 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024. The increase in revenue in the third quarter of 2025 when compared to the second quarter of 2025 was primarily attributable to the following: • We are required to deliver power under power purchase agreements from the Barcarena Power Plant starting in the third quarter of 2025. The Barcarena Power Plant is currently being commissioned, and as such, we partnered with a local energy trader to supply the required power. Revenue recognized for the delivery of power under these PPAs in third quarter of 2025 was $93.8 million. • We entered into sub-charter agreements for the Energos Eskimo commencing in June 2025, and Energos Winter, and Energos Freeze commencing in the third quarter of 2025. The sub-charter revenue of $27.8 million is included in our Terminals and Infrastructure segment. The increase above was offset by a decrease in our terminal revenue due to the following: • We delivered 3.0 TBtu from our Montego Bay Facility and Old Harbour Facility prior to the sale of our Jamaica Business in the second quarter of 2025. The volumes delivered to our customers from our San Juan Facility and La Paz Facility together decreased from 11.2 TBtu in the second quarter of 2025 to 10.7 TBtu in the third quarter of 2025. 51 Table of Contents • We recognized $24.3 million of revenue from cargos sales for the three months ended June 30, 2025. We had no cargo sales for the three months ended September 30, 2025, as we were able to utilize all volumes under our supply contracts in our downstream terminal operations. • The average Henry Hub index pricing used to invoice our downstream customers decreased by 11% for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025. The decrease in revenue in first three quarters of 2025 when compared to the first three quarters of 2024 was primarily attributable to decreased volumes due to the the termination of the grid stabilization project in the first quarter of 2024 and the sale of our Jamaica Business in May 2025. • For the nine months ended September 30, 2025, volumes delivered to downstream customers were 38.7 TBtu as compared to 62.8 TBtu for the nine months ended September 30, 2024. • The higher volumes in the first three quarters of 2024 were 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. Additionally, PREPA's San Juan Facility was undergoing repairs and maintenance in the first quarter of 2025, further decreasing volumes sold in Puerto Rico in the current year. • We delivered 9.4 TBtu from our Montego Bay Facility and Old Harbour Facility prior to the sale of the Jamaica Business in May 2024, compared to 19.8 TBtu during the nine months ended September 30, 2024. • The reduction in volumes delivered from our terminals was partially offset by higher demand from our customers at the La Paz Facility. We delivered 8.4 TBtu through the La Paz Facility during the nine months ended September 30, 2025 compared to 6.5 TBtu during the nine months ended September 30, 2024. The decrease in revenue for the nine months ended September 30, 2025 was partially offset by an increase due to the following: • Revenue recognized for the delivery of power under PPAs from the Barcarena Power Plant in third quarter of 2025 was $93.8 million. • We earned sub-charter revenue for Energos Eskimo, Energos Winter, and Energos Freeze of $27.8 million during nine months ended September 30, 2025 , which is included in our Terminals and Infrastructure segment. • The average Henry Hub index pricing used to invoice our downstream customers increased by 62% for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024. • Revenue from cargos sales was $207.0 million for the nine months ended September 30, 2025, as compared to $199.1 million for the nine months ended September 30, 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. Our subsidiary, Genera, provides 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 $11.9 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025, primarily driven by lower volumes delivered to our customers, including cargo sales, and lower vessel costs, which is partially offset by higher cost incurred for the delivery of power under PPAs from the Barcarena Power Plant. • We delivered lower volumes of LNG to our downstream customers of 10.7 TBtu in the third quarter of 2025, compared to 14.2 TBtu in the second quarter of 2025 predominantly due to sale of our Jamaica Business in May 52 Table of Contents 2025. The weighted average cost of gas purchased increased from $8.84 per MMBtu for the three months ended June 30, 2025 to $9.40 per MMBtu for the three months ended September 30, 2025. • During the three months ended June 30, 2025, we incurred cargo sales costs of $15.7 million. We did not incur any cargo sales costs during the three months ended September 30, 2025. • Vessel costs decreased by $22.7 million during the three months ended September 30, 2025 compared to the three months ended June 30, 2025. The vessel costs were lower in the third quarter as fewer vessels were chartered in our fleet. We assigned vessels used in the Jamaica Business to the buyer during the second quarter of 2025, and we redelivered certain vessels after their charters ended in the third quarter of 2025. The decrease in cost of sales for the quarter was largely offset by a $44.1 million increase related to the delivery of power under PPAs from the Barcarena Power Plant. Cost of sales decreased by $68.1 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024, which was attributable to the following: • We delivered 38.7 TBtu during the nine months ended September 30, 2025 compared to 62.8 TBtu during the nine months ended September 30, 2025, a reduction of 38% in volumes delivered, principally due to the sale of our Jamaica Business and downtime for repairs and maintenance at our San Juan Facility. In addition, our customer terminated the grid stabilization project in the first quarter of 2024, resulting in lower volumes delivered in 2025. • We recognized lower payroll and other operating costs of $60.7 million to provide services under Genera's operations and maintenance contract for the nine months ended September 30, 2025 compared to $77.0 million for the nine months ended September 30, 2024; these costs are passed onto PREPA. The decrease in the costs of gas were offset by higher weighted average cost of gas purchased from $6.65 per MMBtu for the nine months ended September 30, 2024 to $9.01 per MMBtu for the nine months ended September 30, 2025. In the first three quarters of 2025, we incurred $119.5 million of cargo sales costs, compared to $102.3 million incurred in the first three quarters of 2024. Additionally, we incurred $44.1 million in the third quarter related to the delivery of power under PPAs from the Barcarena Power Plant. The weighted-average cost of our LNG inventory balance to be used in our operations as of September 30, 2025 and December 31, 2024 was $10.01 per MMBtu and $6.90 per MMBtu, respectively. Vessel operating expenses Vessel operating expenses relate to direct costs such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees associated with operating vessels. Vessel operating expenses remained consistent between the three months ended September 30, 2025 and 2024. We incurred $3.7 of vessel operating expenses during the nine months ended September 30, 2025 as the sub-charter agreements for certain vessels commenced during 2025 within the segment. No such costs were incurred in this segment in 2024. Operations and maintenance Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance decreased by $1.3 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025. The decrease was primarily attributable to the costs due to the sale of our Jamaica Business in May 2025. The decrease was partially offset by increase in vessel charter costs and port fees. Operations and maintenance increased by $33.4 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024 . The increase is primarily due to higher vessel charter costs, and other operating costs incurred at our Fast LNG unit and the Santa Catarina Facility that were placed into service at the end of 53 Table of Contents 2024. In the first quarter of 2024, our grid stabilization contract was terminated and assets related to the project were sold to PREPA, resulting in a reduction in costs incurred at our San Juan Facility. Ships Segment Three Months Ended, (in thousands of $) September 30, 2025 June 30, 2025 Change Total revenues $ 25,602 $ 38,456 $ (12,854) Vessel operating expenses 5,357 6,291 (934) Segment Operating Margin $ 20,245 $ 32,165 $ (11,920) Nine Months Ended, (in thousands of $) September 30, 2025 September 30, 2024 Change Total revenues $ 102,667 $ 128,224 $ (25,557) Vessel operating expenses 18,824 25,153 (6,329) Segment Operating Margin $ 83,843 $ 103,071 $ (19,228) Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of September 30, 2025 , two 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 $12.9 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025. Total revenue for the Ships segment decreased by $25.6 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 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. Third-party charters of certain vessels that were part of the Energos Formation Transaction ended during the nine months ended September 30, 2025, and we are either using those vessels at our terminal operations or sub-chartering on a long-term basis. Revenue from these vessels are now included in the Terminals and Infrastructure segment. 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 $ 0.9 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025 . Vessel operating expenses decreased $6.3 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024. The vessel operating costs were lower during the nine months ended September 30, 2025 as the vessels Energos Winter and Energos Maria have been utilized for our terminal operations at the conclusion of their third party charters. 54 Table of Contents Other operating results Three Months Ended, Nine Months Ended, (in thousands of $) September 30, 2025 June 30, 2025 Change September 30, 2025 September 30, 2024 Change Selling, general and administrative $ 86,050 $ 57,256 $ 28,794 $ 202,577 $ 223,720 $ (21,143) Transaction and integration costs 19,649 75,384 (55,735) 106,964 6,285 100,679 Depreciation and amortization 50,474 52,870 (2,396) 156,401 123,268 33,133 Asset impairment expense 10,353 117,312 (106,959) 127,911 5,756 122,155 Goodwill impairment expense — 582,172 (582,172) 582,172 — 582,172 Loss (gain) on sale 1,705 (472,699) 474,404 (470,994) 77,140 (548,134) Total operating expense 168,231 412,295 (244,064) 705,031 436,169 268,862 Operating (loss) income (103,589) (387,328) 283,739 (509,396) 308,369 (817,765) Interest expense 210,562 206,408 4,154 630,664 228,850 401,814 Other (income) expense, net (29,042) (56,262) 27,220 (149,241) 60,630 (209,871) Loss on extinguishment of debt, net — 20,320 (20,320) 20,787 9,754 11,033 Loss before income taxes (285,109) (557,794) 272,685 (1,011,606) 9,135 (1,020,741) Tax provision (benefit) 8,247 (967) 9,214 35,950 28,012 7,938 Net loss $ (293,356) $ (556,827) $ 263,471 $ (1,047,556) $ (18,877) $ (1,028,679) 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 by $28.8 million for the three months ended September 30, 2025, compared to the three months ended June 30, 2025. The increase was primarily attributable to a $18.6 million loss from legal proceedings with vendors and additional $8.2 million in bad debt expense associated with receivables that we retained following the sale of our Jamaica Business. The increase was partially offset with lower screening costs incurred during the current quarter for our development projects. Selling, general and administrative decreased by $21.1 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024 primarily due to lower share-based compensation expense and screening costs for our development projects . Due to forfeitures during the first three quarters of 2025, we recognized a reversal of previously recorded share-based compensation expense which significantly lowered the expense for the period. Transaction and integration costs The Company incurred transaction and integration costs of $19.6 million during the three months ended September 30, 2025. During the third quarter of 2025, we initiated a process to evaluate our capital structure and liquidity, and we have retained a financial advisor and legal counsel to assist in this evaluation. Our creditors have also retained financial advisors and legal counsel, and we are responsible for these costs. We incurred $18.6 million towards such professional and consulting fees during the three months ended September 30, 2025. We incurred $107.0 million of transaction and integration costs during the nine months ended September 30, 2025. In addition to costs incurred in the current quarter, we incurred $71.1 million of transaction costs directly attributable to the sale of the Jamaica Business, which included fees for novating a vessel charter to the buyer and contingent fees due to our advisors. Other costs relate to legal fees and other third party costs incurred in connection with amendments to credit agreements. 55 Table of Contents We did not incur significant transaction and integration costs for the three and nine months ended September 30, 2024. Depreciation and amortization Depreciation and amortization decreased by $2.4 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025. Depreciation and amortization expense increased by $33.1 million for the nine months ended September 30, 2025 as compared to the nine months ended September 30, 2024 . The increase in depreciation expense resulted from the Fast LNG project and the Santa Catarina Facility being placed into service in December 2024, and was partially offset by a reduction due to the sale of certain turbines and equipment to PREPA in the first half of 2024, and sale of our Jamaica Business in May 2025. Asset impairment expense For the three months ended September 30, 2025, the impairment charge of $10.4 million principally relates to costs incurred on certain capitalized development project costs; during the third quarter, we determined that it was not probable that we would pursue development of these projects. For the three months ended June 30, 2025, the impairment charge of $117.3 million principally relates to the Lakach deepwater project and the development project in Pennsylvania. We determined that it was not probable that we would pursue development of the Lakach deepwater project, and impaired the capitalized project costs. In addition, after testing the recoverability of the capitalized costs for the development project in Pennsylvania, we concluded that the asset group was not recoverable. Accordingly, we recognized an impairment charge to reduce the carrying value of the asset group to its estimated fair value. We did not recognize any significant impairment expense during the first quarter of 2025. During the nine months ended September 30, 2024, the impairment charge related to the sale of our Miami Facility. Goodwill impairment expense For the nine months ended September 30, 2025 , we recognized an impairment of goodwill of $582.2 million primarily as a result of (i) the significant increase in the weighted average cost of capital which reflected a higher company specific risk premium, and (ii) a reduction in forecasted cash flows following changes in customer revenue projections and the timing of completion of development projects. (Gain) loss on sale In May 2025, the Company completed the sale of its Jamaica Business to Excelerate Energy Limited Partnership (“EELP”), a subsidiary of Excelerate Energy, Inc. for cash consideration of $1,055.0 million, subject to certain purchase price adjustments. During the nine months ended September 30, 2025, we recognized a gain of $471.0 million related to the sale. During the nine months ended September 30, 2024, the Company recognized a loss of $77.1 million from the sale of turbines and related equipment to the PREPA. Interest expense Interest expense increased by $4.2 million for the three months ended September 30, 2025 as compared to the three months ended June 30, 2025. The increase in interest expense was primarily driven by lower interest capitalized of $54.7 million during the quarter ended September 30, 2025 compared to $62.5 million during the quarter ended June 30, 2025 . Interest expense increased by $ 401.8 million for the nine months ended September 30, 2025, as compared to the nine months ended September 30, 2024. The increase was primarily due to an increase in total principal balance outstanding and higher interest rates. The total principal balance on outstanding facilities was $9.1 billion as of September 30, 2025 as compared to total outstanding debt of $7.8 billion as of September 30, 2024. We also capitalized interest expense of $ 191.3 million during the first nine months of 2025 compared to $346.9 million for the nine months ended September 30, 2024, as the Fast LNG project and Santa Catarina Facility were placed into service towards the end of 2024. 56 Table of Contents Other (income) expense, net Other (income) expense, net was $(29.0) million and $(56.3) million for the three months ended September 30, 2025 and June 30, 2025, respectively. Other (income) expense, net was $(149.2) million and $60.6 million for the nine months ended September 30, 2025 and 2024, respectively. The Other income recognized in the three months ended September 30, 2025 and June 30, 2025 was primarily due to foreign currency remeasurement gains, supported by the appreciation of the Mexican pesos and Brazilian real against the U.S. dollar. We earned interest income of $10.9 million and $14.0 million for the three months ended September 30, 2025 and June 30, 2025, respectively, largely from the restricted cash for our development projects in Brazil. We also recognized a gain contingency associated with our sale of Centrais Elétricas de Sergipe Participações S.A, or CELSEPAR in 2022 of $5.2 million upon settlement in the second quarter of 2025. Other income recognized in the first three quarters of 2025 was primarily comprised of foreign currency gain due to remeasurement of U.S. dollar denominated debt in our Brazil subsidiary. We recorded an unrealized gain on fair valuation of our contingent consideration derivative liabilities and embedded contingent interest derivative of $18.5 million during the nine months ended September 30, 2025. The Company also recognized interest income of $39.3 million and $14.0 million during the nine months ended September 30, 2025 and September 30, 2024. Other expense recognized in the nine months ended September 30, 2024 was primarily comprised of foreign currency remeasurement losses and loss on termination of leases of turbines used in the grid stabilization project in Puerto Rico partially offset by interest income. Loss on extinguishment of debt, net We did not incur any loss on extinguishment of debt for the three months ended September 30, 2025. During the six months ended June 30, 2025 , we reduced the available capacity under our Revolving Facility by $270.0 million and recognized $10.6 million of loss on extinguishment of debt, which represents the write-off of unamortized deferred financing costs. We also recognized $5.9 million of loss on extinguishment of debt related to the repayment of the South Power Bonds in conjunction with closing of the sale of our Jamaica Business. Additionally, we made a partial repayment of the Term Loan A using proceeds from the sale and incurred a partial extinguishment loss of $3.8 million. During the nine months ended September 30, 2024 , we recognized a loss on extinguishment of $7.9 million in connection with the prepayment of the Equipment Notes, which represents the prepayment premium and unamortized financing costs. We also recognized a loss on extinguishment relating to a premium of $1.9 million over the repurchase price 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 September 30, 2025 of $8.2 million compared to a tax benefit of $1.0 million for the three months ended June 30, 2025. Our tax provision was $36.0 million and $28.0 million for the nine months ended September 30, 2025 and 2024, respectively. We are recognizing a tax provision on pre-tax losses due to estimated taxes due on the gain from sale of our Jamaica Business, taxation of foreign earnings including estimated tax liabilities under the Pillar Two framework, and recognition of a valuation allowance on our U.S. and foreign 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 we no longer include the results of operations of the Montego Bay Facility and Old Harbour Facility in our financial statements. • Our results of operations include the cost of operating our Fast LNG solution. We placed our first Fast LNG project into service in the fourth quarter of 2024. This project represents our largest ever capital project and 57 Table of Contents placing the asset into service 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, we continue to optimize the asset to enhance liquefaction capacity. Such costs that enhance the asset are 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 September 30, 2025 include our 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. We continued to supply gas to these power generation assets under an island-wide gas sales agreement with PREPA, which initially expired in March 2025. During 2025, the Company and PREPA agreed to a series of short-term extensions of the gas supply agreement while working towards a long-term solution that is in the best interests of both parties and achieves our mutual goal of sustained, efficient power generation for Puerto Rico. In September 2025, both parties reached agreement on contract terms for the long-term supply of LNG to Puerto Rico, which the Financial Oversight and Management Board of Puerto Rico ("FOMB") then made further comments. The Parties remain in negotiations to finalize the new gas supply agreement and submit it for review and approval by the FOMB. The current gas supply agreement is extended on a weekly basis until the new gas supply agreement is approved by the FOMB. There can be no assurances that the long-term gas sale agreement will be executed, and to the extent the Company is not able to execute such an agreement, the Company's future results of operations could be adversely impacted and the impact could be material. Liquidity and Capital Resources Cash Flows The following table summarizes the changes to our cash flows for the nine months ended September 30, 2025 and 2024, respectively : Nine Months Ended September 30, (in thousands of $) 2025 2024 Change Cash flows from: Operating activities $ (575,187) $ 146,200 $ (721,387) Investing activities 195,653 (1,308,554) 1,504,207 Financing activities (254,270) 1,100,877 (1,355,147) Net (decrease) increase in cash, cash equivalents, and restricted cash $ (633,804) $ (61,477) $ (572,327) Cash (used in) / provided by operating activities Our cash flow used in operating activities was $575.2 million for the nine months ended September 30, 2025, which decreased by $721.4 million from cash provided by operating activities of $146.2 million for the nine months ended September 30, 2024. Our net loss for the nine months ended September 30, 2025, when adjusted for non-cash items, increased by $815.1 million from the nine months ended September 30, 2024. Non-cash items during the nine months ended September 30, 2025 included goodwill impairment expense of $582.2 million, and asset impairment expense of $127.9 million related to the Lakach deepwater project and the development project in Pennsylvania. We also recognized a gain on sale of $471.0 million related to the sale of the Jamaica Business. Cash outflows during the nine months ended September 30, 2025 includes significant interest payments resulting from both higher amounts of outstanding debt and increased interest rates. Cash paid for interest, excluding capitalized interest, during 2025 totaled approximately $350 million. We have recognized reduced cash flows following the sale of our Jamaica 58 Table of Contents Business. Following the sale of the Jamaica Business, we continue to incur operational and administrative costs that supported all of our operations, including Jamaica. Additionally, our first FLNG unit was placed in service at the end of 2024, and we have incurred increased operational and maintenance costs as we optimize our LNG production process. Cash provided by / (used in) investing activities Our cash flow provided by investing activities was $195.7 million for the nine months ended September 30, 2025, which increased by $1.5 billion from cash used in investing activities of $1.3 billion for the nine months ended September 30, 2024. Cash flows from investing activities during the nine months ended September 30, 2025 were primarily from proceeds of $949.5 million from the sale of the Jamaica Business. Cash inflows were offset by cash outflows for continued construction of the PortoCem Power Plant and the Puerto Sandino Facility, and for expansion projects in Puerto Rico. Cash outflows for investing activities during the nine months ended September 30, 2024 were used primarily for the continued development of our Fast LNG project and the construction of the PortoCem Power Plant and Barcarena Power Plant. Cash outflows were offset by proceeds 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 (used in) / provided by financing activities Our cash flow used in financing activities was $254.3 million for the nine months ended September 30, 2025, which increased by $1.4 billion from cash provided by financing activities of $1.1 billion for the nine months ended September 30, 2024. During the nine months ended September 30, 2025 we had total borrowings of $1.4 billion, a portion of which were used to repay the Barcarena Debentures in full . We also repaid our Revolving Facility and repaid our short-term borrowings under repurchase agreements, prior to drawing on these facilities. In conjunction with closing the sale of the Jamaica Business, we repurchased all outstanding South Power Bonds for $227.1 million. Throughout the first nine months of 2024, we had total borrowings of $3,594.2 million, with such borrowings primarily used to fund continued development of the Fast LNG project, Barcarena Power Plant, and PortoCem Power Plant. Such borrowings were also used to repay a portion of the 2025 Notes and various asset level financings in Puerto Rico and Brazil. We also repaid our Revolving Facility and short-term borrowings under repurchase agreements, prior to again drawing on these facilities. 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 September 30, 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 $ 13,930,677 $ 340,970 $ 3,547,232 $ 6,283,957 $ 3,758,518 Purchase obligations 15,651,630 299,484 491,060 1,055,951 13,805,135 Lease obligations 559,248 32,791 179,231 149,776 197,450 Total $ 30,141,555 $ 673,245 $ 4,217,523 $ 7,489,684 $ 17,761,103 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 September 30, 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 59 Table of Contents 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 September 30, 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. Our remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, towards these projects is approximately $418 million. 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 $170 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 potential future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments. 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. 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. New 2029 Notes and 2029 Notes Interest payments are due on the New 2029 Notes semi-annually in May and November of each year, and an interest payment of $163.8 million was due on November 17, 2025, with a contractual three-day grace period to November 20, 2025. Prior to the expiration of the contractual three-day grace period, we entered into a forbearance agreement with the beneficial holders of greater than 70% of the New 2029 Notes, pursuant to which the holders agreed to forbear from accelerating or exercising remedies in respect of an event of default that has arisen thereunder on account of the issuer’s failure to pay interest due on November 17, 2025. The term of the forbearance agreement is through December 15, 2025, and upon the termination of the forbearance agreement, if further forbearance or debt restructuring is not agreed to, the holders of the New 2029 Notes could accelerate the outstanding principal balance of the New 2029 Notes, in which case substantially all of our other outstanding debt would become payable on demand. We do not expect to be in compliance with the consolidated first lien debt ratio and fixed charge coverage ratio covenants under the Revolving Facility Credit Agreement and the Term Loan A Credit Agreement for the quarter ending December 31, 2025; see discussion below. The indenture governing the New 2029 Notes contains cross-default provisions that would automatically accelerate the maturity date of all outstanding balances under the New 2029 Notes upon an event 60 Table of Contents of default in the Revolving Credit Agreement and Term Loan A Credit Agreement due to a covenant violation. As such, the outstanding principal balance of the New 2029 Notes has been presented as a current liability. The indenture governing the 2029 Notes contains cross acceleration provisions that would allow these lenders to accelerate the maturity date of outstanding principal balances under the 2029 Notes upon an acceleration of outstanding principal balances under Revolving Facility and Term Loan A Credit Agreement due to a covenant violation. As such, the outstanding principal balance of the 2029 Notes has been presented as a current liability. Revolving Facility I n May 2025, we entered into an amendment to the Revolving Credit Agreement to, among other things, (i) provide 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) permit $270.0 million 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 not require the proceeds of the sale of the Jamaica Business to be used to prepay loans and commitments, (iii) provide that the asset sale sweep mandatory prepayment will no longer apply once aggregate commitments are reduced to $550.0 million and (iv) restrict the Company from prepaying the 2026 Notes in excess of $200.0 million other than to avoid springing maturities unless any such prepayment is made using proceeds from refinancing indebtedness or capital contributions. In May 2025, we repaid $270.0 million of outstanding balance under the Revolving Facility which permanently reduced the borrowing capacity to $730.0 million . Additionally, we have issued letters of credit of $69.5 million in the second quarter of 2025, and including the outstanding letters of credit, we have fully utilized the borrowing capacity of $729.9 million as of September 30, 2025. In November 2025, we entered into an amendment to the Revolving Credit Agreement to, among other things, (a) provide for a covenant holiday with respect to (x) the consolidated first lien debt ratio and fixed charge coverage ratio covenants contained therein fo r the fiscal quarter ended September 30, 2025 and (y) the minimum liquidity requirement contained therein for the fiscal quarter ending December 31, 2025, (b) remove certain flexibility we had to pay dividends and other distributions, and (c) restrict our ability to make payments of principal or interest accruing on certain outstanding indebtedness, including the November 17, 2025 interest payment on the New 2029 Notes. We also do not expect to be in compliance with the consolidated first lien debt ratio and fixed charge coverage ratio covenants for the fiscal quarter ending December 31, 2025. If we do not enter into an agreement with the lenders under the Revolving Facility to provide for a covenant holiday or other covenant relief for the fiscal quarter ending December 31, 2025, by the time we furnish to the administrative agents for the Revolving Facility audited financial statements for such fiscal year, the lenders would have the right to accelerate the repayment of the outstanding principal under the Revolving Facility. If the lenders choose to exercise such rights, substantially all of our outstanding indebtedness could be accelerated. Letter of Credit Facility In May 2025, we entered into the eighth amendment to the Letter of Credit Agreement to, among other things, (i) provide for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio covenants contained therein for the fiscal quarter ended June 30, 2025 and (ii) add a covenant limiting the amount of cash we can use to repurchase the 2026 Notes, other than payments to avoid springing maturities in respect thereof or with proceeds of certain permitted debt or equity refinancing transactions. On July 2, 2025, we entered into a deferral agreement for our Letter of Credit Agreement. The deferral agreement deferred the date on which we were required to cash collateralize the letters of credit scheduled that would remain outstanding on or after July 24, 2025, the then-current maturity date (the “Cash Collateralization Requirement”) until July 17, 2025. The Cash Collateralization Requirement was subsequently deferred in a second deferral agreement, dated July 17, 2025, until July 24, 2025. On July 24, 2025, we entered into an extension agreement to our Letter of Credit Agreement. The extension agreement extended the maturity date to July 31, 2025 and deferred the Cash Collateralization Requirement until July 31, 2025. Pursuant to a second extension agreement on July 31, 2025, the then-current maturity date was extended to August 8, 2025 and the Cash Collateralization Requirement was deferred to August 8, 2025. 61 Table of Contents On August 8, 2025, we entered into the ninth amendment to our Letter of Credit Agreement to, among other things, (i) change the facility from uncommitted to committed; (ii) extend the maturity date to November 14, 2025; (iii) add an asset sale sweep prepayment provision; and (iv) make certain changes to fees and pricing. In addition, the commitments were reduced to approximately $195,000 and were scheduled to automatically reduced on October 5, 2025 to approximately $155,000. On September 30, 2025, we entered into a deferral agreement for our Letter of Credit Agreement to, among other things, further defer the Cash Collateralization Requirement to November 14, 2025. On October 24, 2025, we entered into the tenth amendment and deferral agreement to our Letter of Credit Agreement to, among other things, delay the reduction of commitments until a date that certain letters of credit were issued and/or renewed (not to be later than November 14, 2025). On November 14, 2025, we entered into the eleventh amendment to the Letter of Credit Agreement to, among other things, (a) extend the maturity date of the Letter of Credit Facility to March 31, 2026, (b) provide for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio covenants contained therein for the fiscal quarters ended September 30, 2025 and December 31, 2025, (c) remove the minimum liquidity requirement contained therein with respect to each fiscal quarter, (d) remove certain flexibility we had to pay dividends and other distributions, and (e) restrict our ability to make payments of principal or interest accruing on certain outstanding indebtedness As of September 30, 2025, we had $195,000 of letters of credit outstanding under the Letter of Credit Facility. 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 were required beginning June 2025. The Term Loan B is secured by the same collateral as that secures 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. Additionally, the Term Loan B contains cross acceleration provisions that would allow these lenders to accelerate the maturity date of outstanding principal under the Term Loan B upon an acceleration of outstanding principal balances under Revolving Facility and Term Loan A Credit Agreement due to a covenant violation. As such, the outstanding principal balance of the Term Loan B has been presented as a current liability. 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. In May 2025, we entered into an additional amendment to the Term Loan A Credit Agreement to, among other things, (i) require $55.0 million of proceeds from the sale of the Jamaica Business to be used to prepay a portion of loans currently outstanding; (ii) increase the applicable margin to 6.70% for SOFR loans and 5.70% for Base Rate Loans and implement a Term SOFR floor of 4.30% for initial term loans and a base rate minimum of 5.30%; (iii) require us to make mandatory prepayments with 12.5% of proceeds of a $659.0 million request for equitable adjustment and any other proceeds related to the early termination of contracts associated with the grid stabilization project in Puerto Rico, if and when such proceeds are received. Additionally, this amendment amends certain of the financial covenants, whereby the consolidated first lien debt ratio cannot exceed (i) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (ii) 6.50 to 1.00, for the fiscal 62 Table of Contents quarter ending December 31, 2025, (iii) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 and September 30, 2026 and (iv) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter. The amendment added a fixed charge coverage ratio covenant and removed the debt to total capitalization covenant. We cannot permit the fixed charge coverage ratio for us and our restricted subsidiaries to be less than or equal to 1.00 to 1.00 for the fiscal quarter ending September 30, 2025 and each fiscal quarter thereafter. The first lien debt ratio and the fixed charge coverage ratio covenants were waived for the fiscal quarter ended June 30, 2025. In November 2025, we entered into an amendment to the Term Loan A Credit Agreement to, among other things, (a) provide for a covenant holiday with respect to (x) the consolidated first lien debt ratio and fixed charge coverage ratio covenants contained therein for the fiscal quarter ended September 30, 2025 and (y) the minimum liquidity requirement contained therein for the fiscal quarter ending December 31, 2025(b) remove certain flexibility we had to pay dividends and other distributions and (c) restrict our ability to make payments of principal or interest accruing on certain outstanding indebtedness, including the November 17, 2025 interest payment on the New 2029 Notes. We also do not expect to be in compliance with the consolidated first lien debt ratio and fixed charge coverage ratio covenants for the fiscal quarter ending December 31, 2025. If we do not enter into an agreement with the lenders under the Term Loan A Credit Agreement to provide for a covenant holiday or other covenant relief for the fiscal quarter ending December 31, 2025, by the time we furnish to the administrative agents for the Term Loan A Credit Agreement audited financial statements for such fiscal year, the lenders would have the right to accelerate the repayment of the outstanding principal under the Term Loan A Credit Agreement. If the lenders choose to exercise such rights, substantially all of our outstanding indebtedness could be accelerated. Short-term Borrowings We have an LNG cargo financing arrangement where it may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of September 30, 2025, $73.3 million was due under repurchase arrangements with a weighted average interest rate of 7.95%, and we have amended the agreements on outstanding borrowings to extend the due date to November 14, 2025. Borrowings under this arrangement are uncommitted, and as such, there can be no assurance that we will have a right to extend the due dates on outstanding balances or borrow additional amounts in the future. 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. PortoCem Debentures The PortoCem Debentures included a non-automatic early maturity provision whereby upon multiple downgrades of the Company’s credit rating, early maturity may be declared if approved by the majority of debenture holders. Our credit ratings were downgraded during the first quarter of 2025, triggering the right of the debenture holders to determine if an early maturity event should be declared. On May 23, 2025, the debenture holders unanimously permanently waived their ability to declare an early maturity event due to this credit ratings downgrade. In connection with the debenture holders' decision to not declare an early maturity event, we agreed to provide a bank guarantee of $129.1 million prior to August 17, 2025. On June 5, 2025, we received an additional downgrade of our credit rating, which triggered an non-automatic event of early maturity under the PortoCem Debenture. On June 26, 2025, the debenture holders unanimously permanently waived their ability to declare an early maturity event due to this credit ratings downgrade. No additional collateral was required; 63 Table of Contents however, we were required to provide $50.0 million of the previously required bank guarantee on or before July 7, 2025. The remaining $79.1 million bank guarantee was due prior to August 17, 2025. Additionally, the debenture holders agreed to amend the debenture agreement to suspend the provision that allows for a non-automatic early maturity event upon certain downgrades of our credit rating through August 30, 2026. We provided the required $50.0 million bank guarantee on July 9, 2025, subsequent to the required deadline of July 7, 2025. On August 7, 2025 the debenture holders unanimously waived their ability to declare an early maturity event due to the failure to timely meet this condition in the previous waiver. Additionally, we did not provide the required $79.1 million bank guarantee by the deadline. On October 11, 2025, the debenture holders unanimously permanently waived their ability to declare an early maturity event due to the failure to provide the bank guarantee. The remaining $79.1 million bank guarantee is now due on or before May 10, 2026, and if this guarantee or an equivalent amount of equity contribution to the project company is not made by this date, an automatic early maturity event will exist under the amended debenture agreement. We are discussing providing this bank guarantee with its creditors under new credit arrangements. However, based on our current liquidity, we determined that it is not currently probable that the bank guarantee can be provided, absent an agreement with our existing creditors or new lenders, and as such the PortoCem Debentures continue to be classified as a current liability. If such automatic early maturity event were to occur, substantially all of our outstanding indebtedness would be payable on demand. The PortoCem Debentures contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The PortoCem Debentures do not contain any restrictive financial covenants. EB-5 Loan Agreement Our loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program ("EB-5 Loan Agreement") requires us to create a minimum number of new jobs prior to January 2026 (the "Job Creation Requirement"). During the third quarter of 2025, we determined that it was not probable that development of our ZeroPark project will have created a sufficient amount of jobs by this deadline. After contractual notice and grace periods, if the Jobs Creation Requirement is not met, the lenders would have the ability to accelerate the payment of all outstanding balances under the EB-5 Loan Agreement. As of September 30. 2025, we had an aggregate principal amount of $100.0 million outstanding (the "EB-5 Loan"). None of our other outstanding indebtedness would be impacted by any potential event of default or acceleration of the EB-5 Loan. We are in discussions with the lenders to obtain a waiver. South Power 2029 Bonds On May 14, 2025, we completed the sale of the Jamaica Business. In conjunction with closing, we repurchased all outstanding South Power Bonds for $227.2 million , including a 1.0% prepayment penalty and accrued interest. Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of September 30, 2025 , 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.