Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this 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, 2025 (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 financial statements included in this Quarterly Report, we have evaluated whether conditions exist that give rise to substantial doubt as to our ability to continue as a going concern. Due to the events of default under our debt agreements detailed below, management has concluded that there is substantial doubt as to our ability to continue as a going concern. On March 17, 2026, we entered into the RSA with certain lenders and noteholders under each of these facilities, and upon completion of the transactions contemplated in this agreement, we expect to have a new capital structure and the current debt facilities in default will no longer be outstanding. Existing and potential events of default include missed interest payments under the New 2029 Notes, Term Loan B Credit Agreement, Term Loan A Credit Agreement, 2026 Notes, 2029 Notes and Revolving Credit Agreement and other Specified Defaults (as defined in the RSA), as described in the RSA, which are subject to forbearance in accordance with the RSA. Restructuring Support Agreement and Restructuring Transaction In response to the Company’s ongoing liquidity challenges, and the events of default under the Company’s indentures and credit agreement, on March 17, 2026, the Company entered into a RSA with the Supporting Creditors, including a majority of the holders of the New 2029 Notes, a majority of the lenders under the Term Loan B Credit Agreement and a majority of the lenders under the Revolving Facility. The RSA provides a framework for a comprehensive restructuring transaction designed to address the Company’s capital structure and restore financial stability. Under the terms of the RSA, the holders of the New 2029 Notes, holders of debt under the R-2 Revolving Credit Facility and the holders of the debt under the Term Loan A Credit Agreement, as applicable, will receive 100% of the common equity interests of NFE Brazil Holdings, the parent company of NFE’s Brazil business expected to be separated in connection with the restructuring. In addition, the Supporting Creditors will receive one or a combination of the following: senior secured term loans, non-recourse term loans secured by the Company’s Fast LNG assets, shares of a new class of NFE’s preferred stock as well as shares of NFE’s Class A common stock, and shares of FLNG 2 preferred stock. Certain lenders have also agreed to provide the Company with incremental funding in exchange for additional term loans or additional letter of credit facility capacity to support ongoing operations and liquidity needs. The Restructuring Transaction is expected to close during the third quarter of 2026, upon satisfaction of the remaining conditions. 36 Table of Contents In connection with the Restructuring Transaction, NFE expects to divest its Brazil business, including the Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility, and PortoCem Power Plant. The effectuation of the restructuring will result in a significant reduction of the Company’s outstanding debt and annual interest expense, as the debt facilities currently in default will no longer be outstanding. The Company’s future business will be focused on operational efficiency of its remaining facilities and the cost-effective completion of in-process development projects, with the objective of returning to profitability and generating shareholder value. However, the consummation of the Restructuring Transaction is subject to a number of conditions and approvals, some of which are outside the Company’s control, and there can be no assurance that the transactions will be completed as contemplated. If the restructuring is not successfully implemented, the Company would be required or compelled to pursue alternative in-court restructuring initiatives to preserve value, which would have a material adverse impact on stakeholders and likely result in no recovery to stockholders. For further discussion of the RSA, the Restructuring Plans and the Restructuring Transaction, see Note 2 of our condensed consolidated financial statements. 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. Collectively, our assets and operations reinforce global energy security, enable economic growth, enhance environmental stewardship and transform local industries and communities around the world. 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. Our first floating liquefaction unit, which we refer to as “FLNG 1”, began producing LNG in July 2024, and we source a significant portion of our LNG needs from this facility. Currently, demand for LNG above FLNG 1’s capacity is acquired from third-party suppliers in open market purchases. Starting in 2027, we expect to meet this demand under long-term supply contracts, which are based on an index such as Henry Hub plus a fixed fee component. 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 currently includes one vessel which is currently chartered under a long-term arrangement to a third party and is part of the Energos Formation Transaction (defined below). Vessels that have been in our Ships segment transitioned to the Terminals and Infrastructure segment once we began to utilize the vessels in our own operations. 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 December 2025, we were awarded a new 7-year gas supply agreement with PREPA to deliver up to 75 TBtu of natural gas annually from our San Juan Facility. The new contract establishes security of supply in San Juan for power plants currently running on natural gas and also provides for incremental natural gas volumes to be delivered, allowing for 37 Table of Contents the conversion of additional gas-ready plants currently burning diesel. We do not expect to have to incur significant capital expenditures to be able to supply these additional locations. We continue to provide operation and maintenance services for PREPA’s thermal generation assets through our wholly-owned subsidiary, Genera PR LLC ("Genera"), 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 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 135 MW 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. 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 March 2026, the Company entered into a term sheet to lease its Santa Catarina Facility to a third party that is expected to commence in August 2026. 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 2.05 GW located in the State of São Paulo, within the city limits of Lins. The Santa Catarina Facility will supply natural gas to the Lins power project, and is expected to commence operations in 2031. Upon effectuation of the Restructuring Transaction, we expect to no longer own BrazilCo, including the Santa Catarina Facility. FLNG 1 Our first Fast LNG unit (“FLNG 1”) has been deployed off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million ton per annum (“MTPA”) FLNG unit utilizes CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. This first FLNG unit has been fully commissioned, and we are in the process of increasing available liquefaction capacity through optimization projects. Barcarena Terminal We placed the Barcarena Terminal in service in the second quarter of 2026. The Barcarena Terminal consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Terminal 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 Terminal. For further discussion on the gas supply agreement, see Note 18 of our condensed consolidated financial statements. Upon effectuation of the Restructuring Transaction, we expect to no longer own BrazilCo, including the Barcarena Terminal. Our LNG Supply and Cargo Sales NFE provides reliable, affordable and clean energy supplies to customers around the world, and we currently satisfy customer demand with production from FLNG 1, which we expect to generate up to 70 TBtus annually. We have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to 38 Table of Contents commence in 2027 and 2029. Additional LNG needed to supply expansion of our operations in Puerto Rico and/or our Nicaragua Power Plant will be provided by open market purchases until the commencement of these LNG supply contracts. Geopolitical events have substantially impacted and may continue to impact the natural gas and LNG markets, which have experienced significant volatility in recent years. Our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Pricing for feed gas purchased for own Fast LNG production is based on Henry Hub, which allows us to mitigate exposure to variability in LNG prices. Our long-term supply contracts also contain pricing based on Henry Hub, however, until the commencement of these long-term supply contracts, a portion of our LNG needs will be purchased on the open market which exposes us to volatility in LNG pricing. 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. One vessel is currently chartered to a third party under a long-term arrangement which was part of the Energos Formation Transaction (defined below); and is included in our Ships segment. 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. In November 2025, we completed a transaction with Energos, pursuant to which the Company early terminated the long-term charter agreements with Energos for Energos Eskimo, Energos Winter, Energos Igloo and Energos Freeze and novated associated sub-charter agreements for these vessels to Energos, in exchange for cash consideration of $150.0 million. This transaction resulted in the sale of these vessels that were previously accounted for as a failed sale leaseback. The Company no longer recognizes charter revenues and vessel operating expenses associated with these vessels. Our Development Projects Our projects currently under development include our development of a second modular liquefaction facility to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our power plants located in Pará, Brazil (“Barcarena Power Plant”); our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); and our LNG terminal and power plant in Ireland (“Ireland Facility”). Subsequent to the Restructuring Transaction, we will focus on operational efficiency of our current facilities and cost-effective completion of in-process development projects. 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 Following the completion of the Restructuring Transaction, we do not plan to incur significant capital expenditures to develop our second 1.4 MTPA Fast LNG unit (“FLNG 2”). We are in active discussions with third parties to co-develop 39 Table of Contents FLNG 2, which is expected to take approximately 24 months to complete from the time our partner is engaged. Estimated cost to complete is uncertain and is dependent upon final design and engineering, but we currently expect the remaining cost to be between $750.0 million and $1.5 billion. Barcarena Power Plant The recently completed Barcarena Terminal will also supply our new 630 MW 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 place the Barcarena Power Plant into service in the third quarter of 2026. PortoCem Power Plant 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 1.6 GW 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 Terminal, 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 Terminal. We expect the PortoCem Power Plant to be completed in 2026. Upon effectuation of the Restructuring Transaction, we expect to no longer own BrazilCo, including the Barcarena Power Plant and PortoCem Power Plant. Puerto Sandino Facility We are developing an offshore 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 power plant is substantially complete, and we expect to complete the construction of the terminal and commission both the terminal and the power plant during first half of 2027. 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. In the third quarter of 2023, An Bord Pleanála (“ABP”), Ireland’s planning commission, denied our application for the development of an LNG terminal and power plant. We challenged this decision, and in September 2024, the High Court of Ireland ruled that ABP did not have appropriate grounds for the denial of our permit. In March 2025, ABP withdrew their appeal to the September 2024 decision of the High Court of Ireland. 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. 40 Table of Contents Recent Developments Restructuring Support Agreement and Restructuring Transaction On March 17, 2026, NFE entered into the RSA with the Supporting Creditors. Under the RSA, the Supporting Creditors agree to support the Restructuring Transaction, which involves a comprehensive restructuring of the Company’s principal funded debt obligations. For further discussion on the RSA, the Restructuring Plans and the Restructuring Transaction, see Note 2 of our condensed consolidated financial statements for further discussion. Energos Restructuring Support Agreement On March 8, 2026, the Company entered into a restructuring support agreement with Energos, which was further amended on March 17, 2026 (“Energos RSA”). The Energos RSA, among other things, cancels and terminates the Company's forward starting charter agreement for Nusantara Regas Satu. The Energos RSA will become effective upon completion of the Restructuring Transaction. This transaction will result in the sale of Nusantara Regas Satu that has been accounted for as a failed sale leaseback. Upon closing of the transaction, we expect to derecognize Nusantara Regas Satu from Property, plant and equipment, net, derecognize the related financing obligation, and recognize a non-cash loss of approximately $40.0 million as the carrying amount of the vessel exceeds the financing obligation balance. 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 ("D.C. 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 19, 2025, the D.C. Circuit denied a petition challenging this FERC order, holding that the order reflected an unreviewable exercise of enforcement discretion rather than a de facto authorization for construction or operation. The deadline to seek a writ of certiorari from that decision has expired. On September 26, 2024, the United States Coast Guard ("USCG") filed a Letter of Recommendation ("LOR") 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 LOR to FERC in support of our operations, which we expect to be imminently forthcoming. In concert with our collaboration with the USCG regarding our operational plans, we withdrew our appeal on February 14, 2025. On January 12, 2026, the Acting Captain of the Port of San Juan for the USCG issued a LOR in response to NFE’s filings. The LOR determined that the Port of San Juan waterway is suitable for the transit and docking of larger LNG Carriers. 41 Table of Contents 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 June 30, 2026 compared to Three Months Ended March 31, 2026 and Six Months Ended June 30, 2026 compared to Six Months Ended June 30, 2025 Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets. Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business. 42 Table of Contents The tables below present our segment information for the three months ended June 30, 2026 and March 31, 2026, and for the six months ended June 30, 2026 and June 30, 2025: Three Months Ended June 30, 2026 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 299,248 $ 13,254 $ 312,502 $ — $ 312,502 Cost of sales(1) 210,380 — 210,380 — 210,380 Vessel operating expenses(2) 71 5,902 5,973 — 5,973 Operations and maintenance(2) 41,048 — 41,048 — 41,048 Segment Operating Margin $ 47,749 $ 7,352 $ 55,101 $ — $ 55,101 Three Months Ended June 30, 2026 (in thousands of $) Consolidated Gross margin (GAAP) $ 9,511 Depreciation and amortization 45,590 Consolidated Segment Operating Margin (Non-GAAP) $ 55,101 Three Months Ended March 31, 2026 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 219,681 $ 7,272 $ 226,953 $ — $ 226,953 Cost of sales(1) 199,685 — 199,685 — 199,685 Vessel operating expenses(2) 654 — 654 — 654 Operations and maintenance(2) 48,265 — 48,265 — 48,265 Segment Operating Margin $ (28,923) $ 7,272 $ (21,651) $ — $ (21,651) Three Months Ended March 31, 2026 (in thousands of $) Consolidated Gross margin (GAAP) $ (62,733) Depreciation and amortization 41,082 Consolidated Segment Operating Margin (Non-GAAP) $ (21,651) 43 Table of Contents Six Months Ended June 30, 2026 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 518,929 $ 20,526 $ 539,455 $ — $ 539,455 Cost of sales(1) 410,065 — 410,065 — 410,065 Vessel operating expenses(2) 725 5,902 6,627 — 6,627 Operations and maintenance(2) 89,313 — 89,313 — 89,313 Segment Operating Margin $ 18,826 $ 14,624 $ 33,450 $ — $ 33,450 Six Months Ended June 30, 2026 (in thousands of $) Consolidated Gross margin (GAAP) $ (53,222) Depreciation and amortization 86,672 Consolidated Segment Operating Margin (Non-GAAP) $ 33,450 Six Months Ended June 30, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 699,317 $ 77,065 $ 776,382 $ — $ 776,382 Cost of sales(1) 510,539 — 510,539 — 510,539 Vessel operating expenses(2) 1,777 13,467 15,244 — 15,244 Operations and maintenance(2) 112,343 — 112,343 — 112,343 Segment Operating Margin $ 74,658 $ 63,598 $ 138,256 $ — $ 138,256 Six Months Ended June 30, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 29,075 Depreciation and amortization 109,181 Consolidated Segment Operating Margin (Non-GAAP) $ 138,256 (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. 44 Table of Contents Terminals and Infrastructure Segment Three Months Ended (in thousands of $) June 30, 2026 March 31, 2026 Change Total revenues $ 299,248 $ 219,681 $ 79,567 Cost of sales (exclusive of depreciation and amortization) 210,380 199,685 10,695 Vessel operating expenses 71 654 (583) Operations and maintenance 41,048 48,265 (7,217) Segment Operating Margin $ 47,749 $ (28,923) $ 76,672 Six Months Ended (in thousands of $) June 30, 2026 June 30, 2025 Change Total revenues $ 518,929 $ 699,317 $ (180,388) Cost of sales (exclusive of depreciation and amortization) 410,065 510,539 (100,474) Vessel operating expenses 725 1,777 (1,052) Operations and maintenance 89,313 112,343 (23,030) Segment Operating Margin $ 18,826 $ 74,658 $ (55,832) Total revenue Total revenue for the Terminals and Infrastructure Segment increased by $79.6 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026, and decreased by $180.4 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025. The increase in revenue for the three months ended June 30, 2026 compared to the three months ended March 31, 2026, was primarily attributable to the Company's Barcarena Terminal being placed into service during the quarter, as well as higher volumes delivered in Puerto Rico and Mexico. •Revenues from our Barcarena Terminal, which was placed into service in April 2026 were $59.3 million for the three months ended June 30, 2026. We delivered 6.2 TBtu of gas from the terminal during this period. •Revenues attributable to our La Paz Facility in Mexico increased $39.1 million, primarily driven by higher volumes delivered to customers and a capacity payment true-up. Volume-related revenues increased $33.9 million as volumes increased from 1.5 TBtu to 2.9 TBtu, and revenues increased an additional $5.2 million due to a true-up of the estimated capacity payment recorded in the second quarter of 2026. These increases were partially offset by lower average Henry Hub index prices used to invoice our downstream customers. •Revenues generated by our San Juan Facility in Puerto Rico increased by $19.4 million for the three months ended June 30, 2026 largely due to the increased volume nominations, partially offset by a decrease in the average Henry Hub index pricing used to invoice our downstream customers. This increase was partially offset by lower cargo sales and Brazil power revenue in the second quarter of 2026. •These cargo sales decreased from $43.9 million in the three months ended March 31, 2026 to $24.6 million in the three months ended June 30, 2026. •We are required to deliver power under power purchase agreements (“PPAs”) from the Barcarena Power Plant starting in the third quarter of 2025. As the Barcarena Power Plant is still being commissioned, we have partnered with a local energy trader to supply the required power. Revenue from these arrangements decreased from $35.7 million in the first quarter of 2026 to $27.1 million in the second quarter of 2026, primarily due to lower volumes of power delivered. 45 Table of Contents •In addition, revenue from our subsidiary, Genera, which provides operations and maintenance services in Puerto Rico, decreased from $29.5 million for the three months ended March 31, 2026 to $22.6 million for the three months ended June 30, 2026. •The average Henry Hub index pricing used to invoice our downstream customers decreased by 42% for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The decrease in revenue in the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily attributable to the sale of our Jamaica business, lower cargo sales and other factors described below. •For the six months ended June 30, 2026, volumes delivered to downstream customers were 21.5 TBtu compared to 28.1 TBtu for the six months ended June 30, 2025 due to the sale of our Jamaica business, resulting in $140.7 million lower revenues. •Revenue from cargo sales decreased from $207.0 million for the six months ended June 30, 2025 to $68.5 million for the six months ended June 30, 2026, as we utilized higher gas volumes at our terminal operations. •Revenues from our San Juan Facility decreased $7.9 million due to lower volumes delivered during the six months ended June 30, 2026 compared to the six months ended June 30, 2025. In addition, we generated $11.5 million of revenue from turbine replacement during the six months ended June 30, 2025, with no comparable revenue recognized during the six months ended June 30, 2026. •Vessel charter revenues decreased by $7.9 million, primarily due to the sale of certain vessels to Energos in the fourth quarter of 2025 and the expiration of certain third-party vessel charters. The decreases were partially offset by higher revenues related to the delivery of power under PPAs and commencement of operations at our Barcarena Terminal. •Revenues increased by $62.8 million from delivery of power under PPAs from the Barcarena Power Plant and $59.3 million from gas sales following the commencement of operations at the Barcarena Terminal during the six months ended June 30, 2026. No such revenue was recognized during the six months ended June 30, 2025. •The average Henry Hub index pricing used to invoice our downstream customers increased by 12% for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. 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 Fast LNG unit. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our liquefaction facilities are also included in Cost of sales. 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 increased by $10.7 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026. The increase was primarily attributable to a $57.5 million increase in the cost of operating our Barcarena Terminal, which was placed into service in April 2026. This increase was partially offset by lower cargo sales cost, lower costs associated with the delivery of power under PPAs from the Barcarena Power plant, and lower vessel costs. •While the volumes delivered to our customers remained consistent in the second quarter of 2026 compared to the first quarter of 2026, cost decreased due to a decrease in weighted average cost of gas purchased from $9.23 per MMBtu for the three months ended March 31, 2026 to $8.53 per MMBtu for the three months ended June 30, 2026, primarily driven by a 42% decrease in the Henry Hub index over the same period. •We incurred $14.7 million of costs relating to cargo sales for the three months ended June 30, 2026, as compared to $44.5 million for the three months ended March 31, 2026, consistent with the lower cargo sales discussed above under Revenue. 46 Table of Contents •Cost of sales related to the delivery of power under the PPAs from the Barcarena Power Plant was $33.0 million for the three months ended June 30, 2026, compared to $43.6 million during the three months ended March 31, 2026, in line with the lower volumes of power delivered discussed above under Revenue. •Vessel costs decreased by $6.5 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026. During the three months ended March 31, 2026, the owner of a vessel leased by the Company repossessed the vessel after the Company failed to make certain lease payments, resulting in lower vessel costs during the current period. In addition, the lease for one other vessel expired during the three months ended March 31, 2026, also contributing to the decrease in vessel costs. Cost of sales decreased by $100.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025, attributable to the following: •Cargo sales costs were $59.2 million for the six months ended June 30, 2026, compared to $119.5 million for the six months ended June 30, 2025, consistent with the decrease in cargo sales revenue over the same period, as discussed above under Revenue. •We delivered 46% lower volumes to our customers during the six months ended June 30, 2026 compared to the six months ended June 30, 2025, driven mostly by the sale of our Jamaica business in May 2025, resulting in a $79.1 million decrease in cost of sales. Cost of sales at our La Paz Facility and San Juan Facility also decreased by $20.9 million due to lower volumes delivered. •Vessel costs decreased $66.6 million during the six months ended June 30, 2026 compared to the six months ended June 30, 2025, due to a reduced number of vessels chartered in our fleet. The decrease reflects the assignment of vessels as part of the sale of our Jamaica business in May 2025, and charter expirations or terminations during 2025 and the first two quarters of 2026. •The decrease in cost of sales was partially offset by a $76.6 million increase in cost of sales related to the delivery of power under the PPAs from the Barcarena Power Plant, and a $57.5 million increase in cost of sales related to gas sales following the commencement of operations at our Barcarena Terminal. No such costs were incurred during the six months ended June 30, 2025. The weighted-average cost of our LNG inventory balance to be used in our operations as of June 30, 2026 and December 31, 2025 was $9.01 per MMBtu and $8.35 per MMBtu, respectively. 47 Table of Contents 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. The vessel operating expenses within the Terminals and Infrastructure Segment were not material to our results of operations for the periods presented. 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 $7.2 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026, and decreased $23.0 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025. The decrease in operations and maintenance costs for the three months ended June 30, 2026 compared to the three months ended March 31, 2026 was primarily due to lower planned and unplanned maintenance at our terminal operations, partially offset by higher charter costs for a vessel used at the Barcarena Terminal. The decrease in operations and maintenance costs for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily due to lower vessel charter costs, the sale of our Jamaica business in May 2025, and lower planned and unplanned maintenance at our terminal operations. The decrease in vessel charter costs was mainly driven by the sale of certain vessels as part of the Energos transaction completed in November 2025, the assignment of a vessel in connection with the sale of our Jamaica business, and expiration of certain vessel charters during 2025 and 2026. These decreases were partially offset by operations and maintenance costs at our Barcarena Terminal, which was placed into service in April 2026. Ships Segment Three Months Ended, (in thousands of $) June 30, 2026 March 31, 2026 Change Total revenues $ 13,254 $ 7,272 $ 5,982 Vessel operating expenses 5,902 — 5,902 Segment Operating Margin $ 7,352 $ 7,272 $ 80 Six Months Ended, (in thousands of $) June 30, 2026 June 30, 2025 Change Total revenues $ 20,526 $ 77,065 $ (56,539) Vessel operating expenses 5,902 13,467 (7,565) Segment Operating Margin $ 14,624 $ 63,598 $ (48,974) 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 June 30, 2026, one vessel included in the Energos Formation Transaction was under a third-party charter and is included in this segment. Total revenue Total revenue for the Ships segment, which consists of the vessel Nusantara Regas Satu, increased by $6.0 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026. 48 Table of Contents The total revenue for the Ships segment decreased by $56.5 million compared to the six months ended June 30, 2025. These decreases were primarily attributable to a transaction with Energos, pursuant to which we early terminated the long-term charter agreements with Energos for certain vessels, including Energos Eskimo and Energos Igloo, which were included in the Ships segment during 2025. This transaction resulted in a sale of the two vessels to Energos, resulting in a reduction in charter revenue for the six months ended June 30, 2026 as compared to the same period in 2025. 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. Total vessel operating expenses, primarily related to the vessel Nusantara Regas Satu, increased by $5.9 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026. The vessel operating expenses decreased by $7.6 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025, due to the termination of our long-term charter agreements for Energos Eskimo and Energos Igloo during 2025, as discussed above. Other operating results Three Months Ended, Six Months Ended, (in thousands of $) June 30, 2026 March 31, 2026 Change June 30, 2026 June 30, 2025 Change Selling, general and administrative $ 85,342 $ 47,640 $ 37,702 $ 132,982 $ 108,379 $ 24,603 Transaction and integration costs 72,483 53,284 19,199 125,767 87,285 $ 38,482 Depreciation and amortization 45,590 41,082 4,508 86,672 109,181 $ (22,509) Asset impairment expense — 61,864 (61,864) 61,864 123,129 $ (61,265) Loss (Gain) on sale 404 (146) 550 258 (470,994) $ 471,252 Goodwill impairment expense — — — — 582,172 $ (582,172) Total operating expenses 203,819 203,724 95 407,543 539,152 $ (131,609) Operating income (148,718) (225,375) 76,657 (374,093) (400,896) $ 26,803 Interest expense 226,672 186,880 39,792 $ 413,552 386,698 $ 26,854 Other (income) expense, net 1,236 (43,192) 44,428 $ (41,956) (122,961) $ 81,005 Loss on extinguishment of debt 4,293 — 4,293 $ 4,293 20,787 $ (16,494) (Loss) income before income taxes (380,919) (369,063) (11,856) (749,982) (685,420) $ (64,562) Tax provision (benefit) (7,964) 31,541 (39,505) $ 23,577 36,468 $ (12,891) Net income $ (372,955) $ (400,604) $ 27,649 $ (773,559) $ (721,888) $ (51,671) 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. 49 Table of Contents Selling, general and administrative increased by $37.7 million for the three months ended June 30, 2026, compared to the three months ended March 31, 2026. The increase was primarily attributable to a $15.0 million increase in contingent losses related to certain legal proceedings. The increase also reflected higher screening costs associated with development projects, increased payroll-related expenses, and higher general and administrative costs incurred to support our business operations. Selling, general and administrative increased by $24.6 million for the six months ended June 30, 2026, compared to the six months ended June 30, 2025. The increase was primarily attributable to a $14.2 million increase in contingent losses related to certain legal proceedings, a $5.4 million increase in share-based compensation expense, and a $6.7 million increase in payroll-related costs, as well as higher general and administrative expenses incurred to support our business operations. These increases were partially offset by decreased screening costs for our development projects. Share-based compensation expense for the six months ended June 30, 2025 was reduced by the reversal of previously recognized compensation expense resulting from employee forfeitures, which contributed to the year-over-year increase in share-based compensation expense during the current period. Transaction and integration costs Transaction and integration costs were $72.5 million and $53.3 million for the three months ended June 30, 2026 and March 31, 2026, respectively, and $125.8 million for the six months ended June 30, 2026. These costs were primarily comprised of professional and consulting fees related to our debt restructuring process (Note 2). Transaction and integration costs were $87.3 million for the six months ended June 30, 2025. The Company incurred $67.0 million of transaction and integration costs that were directly attributable to the Jamaica business sale, which included fees for novating a vessel charter to the buyer and contingent fees due to our advisors. The remainder of the transaction and integration costs related to legal and other third party costs incurred by the Company in connection with amendments to credit agreements. Depreciation and amortization Depreciation and amortization increased by $4.5 million for the three months ended June 30, 2026 as compared to the three months ended March 31, 2026. The increase was primarily attributable to the commencement of operations at our Barcarena terminal during the three months ended June 30, 2026. Depreciation and amortization expense decreased by $22.5 million for the six months ended June 30, 2026 as compared to the six months ended June 30, 2025. The decrease in depreciation expense resulted from the sale of our Jamaica business in May 2025, and sale of certain vessels to Energos in November 2025. Asset impairment expense During the six months ended June 30, 2026, the owner of a vessel under an operating lease repossessed the vessel after the Company failed to make certain lease payments. As the Company no longer has control of the leased asset, the Company recognized an impairment charge on the right-of-use asset of $60.6 million. During the six months ended June 30, 2025, the impairment charge of $123.1 million principally relates to the Lakach deepwater project, and certain development projects in Pennsylvania and Puerto Rico. 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 projects in Pennsylvania and Puerto 50 Table of Contents Rico, we concluded that the asset groups were not recoverable. Accordingly, we recognized an impairment charge to reduce the carrying value of the asset groups to its estimated fair value. There was no asset impairment expense during the three months ended June 30, 2026. Loss (Gain) on sale There was no material gain or loss on sale for the three months ended June 30, 2026 and three months ended March 31, 2026. Gain on sale was $471.0 million for the six months ended June 30, 2025 related to the sale of the Jamaica business in May 2025. No comparable transaction occurred during the six months ended June 30, 2026. Goodwill impairment expense For the six months ended June 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.There was no goodwill impairment expense recognized during the three months ended June 30, 2026, three months ended March 31, 2026, and six months ended June 30, 2026. Interest expense Interest expense increased by $39.8 million for the three months ended June 30, 2026 compared to the three months ended March 31, 2026, and by $26.9 million for the six months ended June 30, 2026 compared to the six months ended June 30, 2025. The key driver for the increase was the issuance of additional debt during the second quarter of 2026 and higher interest rates on certain existing debt obligations. In addition, interest expense decreased by $18.6 million for the quarterly comparison and $27.1 million for the year-to-date comparison. The reduction in capitalized interest was primarily attributable to the completion of the Barcarena Terminal in April 2026 and reduced capitalization associated with the FLNG 2 project. For the year-to-date comparison, the reduction also reflected the impairment of certain projects during the second half of 2025, which reduced the amount of interest eligible for capitalization. Other (income) expense, net Other (income) expense, net was $1.2 million and $(43.2) million for the three months ended June 30, 2026 and March 31, 2026, respectively. Other (income) expense, net was $(42.0) and (123.0) million for the six months ended June 30, 2026 and 2025, respectively. Other (income) expense, net for these periods primarily reflected remeasurement gains and losses related to our operations in Mexico and Brazil, and gains or losses from the fair value remeasurement of foreign currency derivative contracts and contingent consideration arrangements. Other income also included interest income, which was derived largely from the restricted cash related to our development projects in Brazil. Loss on extinguishment of debt During the three and six months ended June 30, 2026, we recorded a total loss on extinguishment of debt of $4.3 million. This included a $3.7 million loss related to the repayment of the Turbine Financing due July 2027 and a $0.6 million loss related to the repayment of the Brazil Bridge Term loan. There was no loss on extinguishment of debt during the three months ended March 31, 2026. 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 representing 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 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. Tax provision We recognized a tax benefit for the three months ended June 30, 2026 of $(8.0) million compared to a tax provision of $31.5 million for the three months ended March 31, 2026. Our tax provision was $23.6 million and $36.5 million for the 51 Table of Contents six months ended June 30, 2026 and June 30, 2025, respectively. The tax benefit recognized in the second quarter of 2026 was primarily driven by a decrease in estimated expense under the Organization for Economic Cooperation and Development's Pillar Two framework, as well as a decrease in the valuation allowance in certain of our foreign subsidiaries. Factors Impacting Comparability of Our Financial Results Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons: •Our historical results of operations include our Jamaica business. In May 2025, we completed the sale of our Jamaica business, and after this point, we no longer include the results of operations of the Montego Bay Facility and Old Harbour Facility in our financial statements. •Our current LNG sourcing does not consider any future long-term supply contracts. Since our first Fast LNG project was placed into service in the fourth quarter of 2024, we source a significant portion of our LNG needs from FLNG 1. Currently, demand for LNG above FLNG 1’s capacity is acquired from third-party suppliers in open market purchases. Starting in 2027, we expect to meet this demand under long-term supply contracts, which are based on an index such as Henry Hub plus a fixed fee component. •Our historical financial results include BrazilCo and do not reflect the contemplated effect of the Restructuring Transaction. The Restructuring Transaction contemplates the separation of our Brazil business, the exchange of existing debt for new debt and equity securities (including the issuance of CoreCo Convertible Preferred Stock and new shares of our Class A common stock), and the incurrence of new term loans and preferred equity at various subsidiaries. These changes will materially impact our reported interest expense, outstanding debt, equity balances, cost of borrowing and earnings per share calculations. In addition, the mandatory conversion of CoreCo Convertible Preferred Stock, potential future equity issuances, and the implementation of new incentive plans may result in further dilution and changes to our financial metrics. As a result, our future financial results will not be directly comparable to our historical results. •We have reached compromise agreements to reduce expenses which are not reflected in our historical financial results. Over the past several months, we reached compromise agreements with vendors, service providers and other partners to materially reduce our outstanding obligations. These cost savings are expected to further impact the comparability of our financial results to prior periods by lowering our ongoing expense base and improving our overall financial position moving forward. Liquidity and Capital Resources Cash Flows The following table summarizes the changes to our cash flows for the six months ended June 30, 2026 and 2025, respectively: Six Months Ended June 30, (in thousands of $) 2026 2025 Change Cash flows from: Operating activities $ (278,241) $ (336,191) $ 57,950 Investing activities (83,848) 452,517 (536,365) Financing activities 497,393 (309,461) 806,854 Cash used in operating activities Our cash flow used in operating activities was $278.2 million for the six months ended June 30, 2026, which decreased by $58.0 million from cash used in operating activities of $336.2 million for the six months ended June 30, 2025. Our net loss for the six months ended June 30, 2026, when adjusted for non-cash items, was $573.0 million and $316.8 million for the six months ended June 30, 2026 and 2025, respectively. 52 Table of Contents Cash outflows during the six months ended June 30, 2026 were impacted by significant professional and consulting fees relating to our capital restructuring process. These outflows were partially offset by improved collections on outstanding receivables and as a result of liquidity constraints, we delayed certain interest payments, increasing accrued interest. Cash used in / (provided by) investing activities Our cash flow used in investing activities was $83.8 million for the six months ended June 30, 2026, which decreased by $536.4 million from cash provided by investing activities of $452.5 million for the six months ended June 30, 2025. Cash flows used in investing activities during the six months ended June 30, 2026 were used primarily for capital expenditures for continued construction of the PortoCem Power Plant and Puerto Sandino Facility, of which $16.1 million of these capital expenditures was paid significantly beyond our vendors customary payment terms, and as such, is presented as a financing activity. Cash flows from investing activities during the six months ended June 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. Cash provided by / (used in) financing activities Our cash flow provided by financing activities was $497.4 million for the six months ended June 30, 2026, which increased by $806.9 million from cash used in financing activities of $(309.5) million for the six months ended June 30, 2025. Cash flows provided by financing activities during the six months ended June 30, 2026 were primarily from proceeds on borrowings of debt of $1.2 billion, with cash outflows partially offset by $674.2 million of repayments. We received $885.0 million of proceeds under the New Brazil Notes, primarily used to repay existing debt. Additionally, we received $265.8 million of proceeds from the sale of certain turbine assets, which was classified as cash flows provided by financing activities as the transaction was accounted for as a failed sale and leaseback. We used the proceeds to repay existing debt and to provide additional liquidity. We also received $50.0 million of proceeds from the Brazil Bridge Term Loan, which was repaid using the proceeds from the New Brazil Notes. During the six months ended June 30, 2025 we had total borrowings of $1.3 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. Contractual Obligations We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2025 and includes those contractual obligations of BrazilCo, which will no longer be owed by us upon completion of the Restructuring Transaction: (in thousands of $) Total Less than Year 1 Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 9,661,351 $ 7,452,300 $ 391,064 $ 264,245 $ 1,553,742 Purchase obligations 17,954,542 211,618 769,000 1,769,116 15,204,808 Lease obligations 538,443 104,559 174,499 112,386 146,999 Total $ 28,154,336 $ 7,768,477 $ 1,334,563 $ 2,145,747 $ 16,905,549 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 December 31, 2025. A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be 53 Table of Contents recognized as a bullet payment at the end of the charters. As neither these third-party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above. Purchase obligations We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of December 31, 2025. We have construction purchase commitments in connection with our development projects, including our Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant and PortoCem Power Plant, and any remaining unpaid commitments on our FLNG projects. 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 $271.0 million. We have secured financing commitments to continue to develop our Barcarena Power Plant and PortoCem Power Plant, which represents approximately $97.0 million of our upcoming committed capital expenditures. Following the completion of the Restructuring Transaction, we do not plan to incur significant capital expenditures to develop FLNG 2. We are in active discussions with third parties to co-develop FLNG 2, which is expected to take approximately 24 months to complete from the time our partner is engaged. Estimated cost to complete is uncertain and is dependent upon final design and engineering, but we currently expect the remaining cost to be between $750.0 million and $1,500.0 million. 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. PortoCem Financings On May 10, 2026, the Company did not provide the $79.1 million bank guarantee that was due to the holders under the PortoCem Debentures (as defined in the Company's Annual Report on Form 10-K) by June 24, 2026. Additionally, other non-financial requirements due on April 30, 2026 were not met, including certain financial ratio and certification requirements. On July 17, 2026, the debenture holders unanimously waived their ability to declare an early maturity event through March 31, 2027 and January 30, 2027, respectively, due to the Company's credit rating downgrades and the Company's non-compliance with other non-financial requirements, in exchange for the Company's contribution of $70.0 million into the PortoCem power plant project by August 21, 2026 as well as an additional supplementary guarantee of $59.1 million by January 30, 2027. The outstanding principal balance of the PortoCem Debentures remains presented as a current liability as of June 30, 2026, given the conditional nature of the waivers obtained and the remaining conditions to be satisfied. Following the completion of the Restructuring Transaction, the Company will no longer own BrazilCo, and the liabilities of BrazilCo, including the PortoCem Debentures will no longer be included in the Company's consolidated financial statements. 54 Table of Contents Turbine Financing Obligation, due July 2036 In April 2026, the Company completed a transaction with Macquarie Energy LLC (“Macquarie”), pursuant to which ownership of nine turbines were transferred to Macquarie in exchange for approximately $265.9 million in cash. Concurrently, the Company entered into a lease agreement to lease back the same turbines under a 10-year lease term with a commencement date of July 1, 2026. These turbines were subject to the forward starting lease with the Company, which prevents the recognition of the sale of these turbines, and therefore these turbines continued to be recognized on the Consolidated Balance Sheets as Construction in progress, and the proceeds were recognized as a financing obligation within Debt. The Company used the proceeds to repay existing debt obligations, specifically the Turbine Financing due July 2027 and the Short-Term Borrowings (both as defined in the Company's Annual Form 10-K), and to provide additional liquidity. The lease subsequently commenced on July 1, 2026 and the Company has preliminarily determined that the lease will be classified as an operating lease effective July 1, 2026, which is expected to effectuate the sale of these turbines. As a result, during the quarter ending September 30, 2026, the Company expects that the turbine assets will be derecognized as well as the associated financing obligation, with any resulting gain or loss recognized in the Condensed Consolidated Statements of Operations and Comprehensive (Loss) Income. Brazil Bridge Credit Agreement On April 14, 2026, NFE Brazil Holdings Limited (“NFE Brazil Holdings”), an indirect subsidiary of NFE, entered into a credit agreement (the “Brazil Bridge Credit Agreement”) for a senior secured, multiple draw term loan facility of $50.0 million (the “Brazil Bridge Term Loan Facility”). The full amount was drawn on April 14, 2026 (the “Brazil Bridge Term Loan”). The Brazil Bridge Term Loan Facility bears interest at a rate of 10% per annum, which will be paid-in-kind. Additionally, the Company incurred a 2.0% lender fee that was paid in kind, which was recorded as a debt discount and is amortized over the term of the loan using the effective interest method. The Brazil Bridge Term Loan was repaid in full on June 22, 2026, with the proceeds from the issuance of the New Brazil Notes. New Brazil Notes On June 22, 2026, NFE Brazil Financing Limited, an indirect subsidiary of NFE, completed a private offering of senior secured notes due 2029 and issued $973.5 million aggregate principal amount of Senior Secured Notes due 2029 (the “New Brazil Notes”), including 10% of commitment fees paid in kind, which was recorded as a discount. The notes bear interest at a rate of 12.0% per annum, payable in kind semi-annually beginning on November 15, 2026 and mature on November 15, 2029. A portion of the proceeds from the issuance of the New Brazil Notes of $477.1 million was used to repay the Brazil Bridge Term Loan and the Brazil Financing Notes (as defined in the Company's Annual Form 10-K). Upon completion of the Restructuring Transaction contemplated under the RSA, NFE will no longer own BrazilCo, and the liabilities of BrazilCo, including the New Brazil Notes, will no longer be included in the Company's consolidated financial statements. Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of June 30, 2026, 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 4 to our notes to condensed consolidated financial statements included elsewhere in this Quarterly Report.