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 “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. 33 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 34 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. 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 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. 35 Table of Contents 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 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”); 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 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. 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. We have substantially completed our Barcarena Facility and are in process of final commissioning. 36 Table of Contents The Barcarena Facility 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 second quarter of 2026. 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 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. Upon effectuation of the Restructuring Transaction, we expect to no longer own BrazilCo, including the Barcarena Facility, 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 p ermit. 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. 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. 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 37 Table of Contents 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 new 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. 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 March 31, 2026 compared to Three Months Ended December 31, 2025 and Three Months Ended March 31, 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 38 Table of Contents is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business. The tables below present our segment information for the three months ended March 31, 2026, December 31, 2025 and March 31, 2025: 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) Three Months Ended December 31, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 379,067 $ 16,677 $ 395,744 $ — $ 395,744 Cost of sales (1) 211,157 — 211,157 — 211,157 Vessel operating expenses (2) 690 3,363 4,053 — 4,053 Operations and maintenance (2) 48,866 — 48,866 — 48,866 Segment Operating Margin $ 118,354 $ 13,314 $ 131,668 $ — $ 131,668 Three Months Ended December 31, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 86,671 Depreciation and amortization 44,997 Consolidated Segment Operating Margin (Non-GAAP) $ 131,668 39 Table of Contents Three Months Ended March 31, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 433,673 $ 38,609 $ 472,282 $ — $ 472,282 Cost of sales (1) 302,377 — 302,377 — 302,377 Vessel operating expenses (2) — 7,176 7,176 — 7,176 Operations and maintenance (2) 54,940 — 54,940 — 54,940 Segment Operating Margin $ 76,356 $ 31,433 $ 107,789 $ — $ 107,789 Three Months Ended March 31, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 51,478 Depreciation and amortization 56,311 Consolidated Segment Operating Margin (Non-GAAP) $ 107,789 (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. Terminals and Infrastructure Segment Three Months Ended (in thousands of $) March 31, 2026 December 31, 2025 Change March 31, 2025 Change Total revenues $ 219,681 $ 379,067 $ (159,386) $ 433,673 $ (213,992) Cost of sales (exclusive of depreciation and amortization) 199,685 211,157 (11,472) 302,377 (102,692) Vessel operating expenses 654 690 (36) — 654 Operations and maintenance 48,265 48,866 (601) 54,940 (6,675) Segment Operating Margin $ (28,923) $ 118,354 $ (147,277) $ 76,356 $ (105,279) Total revenue Total revenue for the Terminals and Infrastructure Segment decreased by $159.4 million for the three months ended March 31, 2026 compared to the three months ended December 31, 2025, and decreased by $214.0 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025. The decrease in revenue in the first quarter of 2026 compared to the fourth quarter of 2025 was primarily attributable to lower cargo and power sales recognized during the three months ended March 31, 2026, as well as additional revenue recognized relating to the settlement agreement with our customer during the three months ended December 31, 2025. • In December 2025, we entered into a settlement agreement with our customer for $142.0 million, related to the early termination of our contract to provide emergency power services in Puerto Rico, and we recognized revenue of $74.8 million. • We are required to deliver power under power purchase agreements (“PPAs”) 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. During the first quarter of 2026, PPAs with 40 Table of Contents certain local distribution companies were suspended. As a result, the Company was required to procure and deliver less power, resulting in decreased revenue from $109.7 million in the fourth quarter of 2025 to $35.7 million in the first quarter of 2026. • We recognized $43.9 million of revenue from cargos sales for the three months ended March 31, 2026 compared to $69.4 million for the three months ended December 31, 2025. • The Company recognized a $16.4 million decrease in revenues related to vessel charters due to the sale of certain vessels to Energos in the fourth quarter of 2025 and end of third-party charters for certain vessels. • These decreases were partially offset by increased volumes delivered to downstream terminal customers from 6.4 TBtu in the fourth quarter of 2025 to 6.9 TBtu in the first quarter of 2026, primarily due to higher volumes offtake at our San Juan Facility. This increase in volumes resulted in a $12.7 million increase in revenue. • The decreases were also partially offset by a $20.6 million increase in revenues attributable to our Mexico operations, most of which is related to higher revenue recognized for an estimated capacity fee payment in the first quarter of 2026 compared to the three months ended December 31, 2025. • The average Henry Hub index pricing used to invoice our downstream customers increased by 42% for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The decrease in revenue in the first quarter of 2026 compared to the first quarter of 2025 was primarily attributable to the sale of our Jamaica business and lower cargo sales. The decrease was partially offset by higher revenues related to the delivery of power under PPAs from the Barcarena Power Plant. • For the three months ended March 31, 2026, volumes delivered to downstream customers were 6.9 TBtu compared to 13.8 TBtu for the three months ended March 31, 2025 due to the sale of our Jamaica business, resulting in $94.1 million lower revenues. • Revenue from cargos sales decreased from $182.7 million to $43.9 million for the three months ended March 31, 2025 and March 31, 2026, respectively. • The decrease in revenue was partially offset by an increase of $35.7 million from delivery of power under PPAs from the Barcarena Power Plant during the three months ended March 31, 2026. No such revenue was recognized in the three months ended March 31, 2025. • The average Henry Hub index pricing used to invoice our downstream customers increased by 38% for the three months ended March 31, 2026 as compared to the three months ended March 31, 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 decreased by $11.5 million for the three months ended March 31, 2026 compared to the three months ended December 31, 2025, primarily driven by reduced costs of cargo sales. Increased gas costs were largely offset by lower vessel related costs in the first quarter of 2026. • In the first quarter of 2026, we incurred $44.5 million of cargo sales costs as compared to $54.3 million for the three months ended December 31, 2025. • We delivered 8% higher volumes to our customers in the first quarter of 2026 compared to the last quarter of 2025. The weighted average cost of gas purchased increased from $8.58 per MMBtu for the three months ended 41 Table of Contents December 31, 2025 to $9.23 per MMBtu for the three months ended March 31, 2026. In addition, the Henry Hub index increased by 42% over the same period. Cost of sales decreased by $102.7 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 2025, which was attributable to the following: • Cargo sales costs incurred during three months ended March 31, 2026 were $44.5 million compared to $103.8 million during the three months ended March 31, 2025, consistent with the level of cargo sales during the corresponding periods. • We delivered 50% lower volumes to our customers during the first quarter of 2026 compared to the first quarter of 2025, driven mostly by the sale of our Jamaica business in May 2025, resulting in a $52.6 million decrease in cost of sales. • Vessel costs decreased by $32.8 million, for the three months ended March 31, 2026 compared to the three months ended March 31, 2025, due to the reduced number of vessels chartered in our fleet. The decrease reflects the assignment of vessels related to the Jamaica business that we sold in May 2025, and charter expirations or terminations during 2025 and the first quarter of 2026. • The decrease in cost of sales was partially offset by an increase in cost of sales of $43.6 million related to the delivery of power under the PPAs from the Barcarena Power Plant. No such costs were incurred during the three months ended March 31, 2025. The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2026 and December 31, 2025 was $8.38 per MMBtu and $8.35 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. The vessel operating expenses 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 remained relatively consistent between the three months ended March 31, 2026 and the three months ended December 31, 2025, increasing by $0.6 million. Operations and maintenance expenses decreased by $6.7 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025 . The decrease was primarily attributable to the lower operating and maintenance costs resulting from the sale of our Jamaica business in May 2025. This decrease was partially offset by higher planned maintenance at our San Juan Facility during the three months ended March 31, 2026. Ships Segment Three Months Ended, (in thousands of $) March 31, 2026 December 31, 2025 Change March 31, 2025 Change Total revenues $ 7,272 $ 16,677 $ (9,405) $ 38,609 $ (31,337) Vessel operating expenses — 3,363 (3,363) 7,176 (7,176) Segment Operating Margin $ 7,272 $ 13,314 $ (6,042) $ 31,433 $ (24,161) 42 Table of Contents Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of March 31, 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 decreased $9.4 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025 , and decreased $31.3 million compared to the three months ended March 31, 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 Energos Eskimo and Energos Igloo to Energos and a reduction in charter revenue for the three months ended March 31, 2026 compared to the three months ended December 31, 2025 and March 31, 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. Vessel operating expenses were $3.4 million and $7.2 million for the three months ended December 31, 2025 and March 31, 2025, respectively. We did not incur any vessel operating expenses for the three months ended March 31, 2026 related to the vessel Nusantara Regas Satu, as such costs are borne by the third-party charterer. Other operating results Three Months Ended, (in thousands of $) March 31, 2026 December 31, 2025 Change March 31, 2025 Change Selling, general and administrative $ 47,494 $ 112,596 $ (65,102) $ 51,820 $ (4,326) Transaction and integration costs 53,284 54,792 (1,508) 11,931 41,353 Depreciation and amortization 41,082 44,997 (3,915) 56,311 (15,229) Asset impairment expense 61,864 732,954 (671,090) 246 61,618 (Gain) on sale — (199,944) 199,944 — — Goodwill impairment expense — 15,938 (15,938) — — Total operating expenses 203,724 761,333 (557,609) 120,308 83,416 Operating income (225,375) (629,664) 404,289 (12,519) (212,856) Interest expense 186,880 192,929 (6,049) 200,309 (13,429) Other (income) expense, net (43,192) 5,934 (49,126) (63,937) 20,745 Loss on extinguishment of debt, net — (850) 850 467 (467) (Loss) income before income taxes (369,063) (827,677) 458,614 (149,358) (219,705) Tax provision (benefit) 31,541 19,386 12,155 26,068 5,473 Net income $ (400,604) $ (847,063) $ 446,459 $ (175,426) $ (225,178) 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. 43 Table of Contents Selling, general and administrative decreased by $65.1 million for the three months ended March 31, 2026, compared to the three months ended December 31, 2025. We recorded $45.6 million of contingent losses related to certain legal proceedings during the three months ended December 31, 2025. There were no significant incremental contingent losses recorded during the three months ended March 31, 2026. In addition, screening costs for development projects, and payroll and bonus expenses decreased by $14.8 million during the first quarter of 2026. Selling, general and administrative decreased by $4.3 million for three months ended March 31, 2026, compared to the three months ended March 31, 2025. The decrease was primarily driven by an $11.5 million reduction in screening costs for development projects, partially offset by higher legal and professional fees and share-based compensation expense. The share-based compensation expense was lower in the first quarter of 2025 due to the reversal of previously recorded expense related to forfeitures during that period. Transaction and integration costs We incurred transaction and integration costs of $53.3 million and $54.8 million during the three months ended March 31, 2026 and December 31, 2025, respectively. These costs were primarily comprised of professional and consulting fees related to our debt restructuring process. The transaction and integration costs of $11.9 million during the three months ended March 31, 2025 primarily related to legal fees and other third-party costs incurred in connection with amendments to certain credit agreements. In addition, during the first quarter of 2025, we incurred $3.9 million of legal fees related to the sale of our Jamaica business. Depreciation and amortization Depreciation and amortization decreased by $3.9 million for the three months ended March 31, 2026 as compared to the three months ended December 31, 2025. The decrease was primarily attributable to the sale of certain vessels to Energos in November 2025. Depreciation and amortization expense decreased by $15.2 million for the three months ended March 31, 2026 as compared to the three months ended March 31, 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 three months ended March 31, 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 three months ended December 31, 2025, as part of the Company’s ongoing discussions with creditors, the Company has determined that it was not probable that it would pursue the development of certain Fast LNG projects and the ZeroParks hydrogen project and recognized impairment charges of $733.0 million to reduce the carrying values of the asset groups to their estimated fair value. There was no material asset impairment expense during the three months ended March 31, 2025. (Gain) loss on sale The Company had no significant asset sales during the first quarter of 2026. For the three months ended December 31, 2025, the Company recorded a gain of $199.9 million. In November 2025, we completed a transaction with Energos, pursuant to which the Company early terminated the long-term charter agreements with Energos for certain vessels and novated associated sub-charter agreements for these vessels to Energos, in exchange for cash considerations of $150.0 44 Table of Contents million. The Company recognized a gain of $217.1 million from the transaction, which was partially offset by a $17.2 million adjustment to the gain on sale of the Jamaica business. Goodwill impairment expense During the three months ended December 31, 2025, we recognized an impairment of goodwill of $15.9 million in our Ships segment, primarily as a result of a reduction in forecasted cash flows following the sale of certain vessels to Energos. There was no goodwill impairment expense recognized during the three months ended March 31, 2026 and 2025. Interest expense Interest expense decreased marginally by $6.0 million for the three months ended March 31, 2026 compared to the three months ended December 31, 2025, primarily due to lower outstanding debt resulting from the vessel sale transaction completed during the fourth quarter of 2025, with the decrease partially offset by higher interest expense incurred during continuance of events of default under certain of our debt agreements. Interest expense decreased by $13.4 million for the three months ended March 31, 2026 compared to the three months ended March 31, 2025. The decrease was driven by lower outstanding debt resulting from the vessel sale transaction, and re payment of debt related to the Jamaica business. The decreases were partly offset by higher interest expense resulting from the issuance of additional debt and higher interest rates. Other (income) expense, net Other (income) expense, net was $(43.2) million, $5.9 million and $(63.9) million for the three months ended March 31, 2026, December 31, 2025 and March 31, 2025, respectively. Other (income) expense for these periods primarily reflected remeasurement gains and losses on U.S. dollar denominated debt held by our Brazil subsidiary, driven by fluctuations in the Brazilian Real relative to the U.S. Dollar, as well as gains or losses from the fair value remeasurement of derivative contracts. 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 The Company had no material extinguishment of debt for the three months ended March 31, 2026, December 31, 2025, and March 31, 2025 . Tax provision We recognized a tax provision for the three months ended March 31, 2026 of $31.5 million compared to a tax provision of $19.4 million for the three months ended December 31, 2025 and a tax provision of $26.1 million for the three months ended March 31, 2025. The tax provision recognized in the first quarter of 2026 was primarily driven by estimated Pillar 2 expense, as well as, taxes on our foreign earnings in certain jurisdictions where we operate. 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. 45 Table of Contents • 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 three months ended March 31, 2026 and 2025, respectively : Three Months Ended March 31, (in thousands of $) 2026 2025 Change Cash flows from: Operating activities $ (118,902) $ (7,237) $ (111,665) Investing activities (43,566) (250,542) 206,976 Financing activities (11,008) 94,615 (105,623) Net decrease in cash, cash equivalents, and restricted cash $ (173,476) $ (163,164) $ (10,312) Cash used in operating activities Our cash flow used in operating activities was $118.9 million for the three months ended March 31, 2026, which increased by $111.7 million from cash used in operating activities of $7.2 million for the three months ended March 31, 2025. Our net loss for the three months ended March 31, 2026, when adjusted for non-cash items, increased by $156.6 million from the three months ended March 31, 2025. Cash outflows during the three months ended March 31, 2026 were impacted by significant professional and consulting fees relating to our capital restructuring process. We have recognized reduced cash flows following the sale of our Jamaica Business in 2025. Following the sale of the Jamaica business during 2025, we continue to incur operational and administrative costs that supported all of our operations. Cash used in investing activities Our cash flow used in investing activities was $43.6 million for the three months ended March 31, 2026, which decreased by $207.0 million from cash used in investing activities of $250.5 million for the three months ended March 31, 2025. Cash flows used in investing activities during the three months ended March 31, 2026 were used primarily for capital expenditures for continued construction of the PortoCem Power Plant and the Puerto Sandino Facility, of which $5.0 million of these capital expenditures was paid significantly beyond our vendors customary payment terms, and as such, is presented as a financing activity. Cash outflows for investing activities during the three months ended March 31, 2025 were used primarily for continued development of our onshore FLNG project and the construction of the PortoCem Power Plant. 46 Table of Contents Cash (used in) / provided by financing activities Our cash flow used in financing activities was $11.0 million for the three months ended March 31, 2026, which increased by $105.6 million from cash provided by financing activities of $94.6 million for the three months ended March 31, 2025. Cash flows used in financing activities during the three months ended March 31, 2026 were primarily used for capital expenditures paid significantly beyond our vendors customary payment terms. During the three months ended March 31, 2025 we had total borrowings of $943.6 million, with such borrowings primarily used to fund continued development of the onshore FLNG project and for other corporate expenses . Such borrowings were also used to repay the Barcarena Debentures in full . We also repaid our Revolving Facility by $275.0 million. 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 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 million. We have secured financing commitments to continue to develop our Barcarena Power Plant and PortoCem Power Plant, which represents approximately $97 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 47 Table of Contents 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. EB-5 Loan Agreement On March 13, 2026, the Company entered into a term sheet with CanAm Texas Regional Center LP. IV., a Delaware limited partnership in respect of the EB-5 Loan Agreement that contemplates, among other things, the incurrence by the Company of a new unsecured note in the aggregate principal amount of $22.5 million, with an interest rate of 7.0% per annum, with the option to pay interest in kind, and that matures on December 31, 2029. Letter of Credit Facility In March 2026, the Company entered into an amendment to the Letter of Credit Facility to extend the maturity date to September 15, 2026. As of March 31, 2026, the Company had $195.6 million of letters of credit outstanding under the Letter of Credit Facility. 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). If the Company fails to provide the bank guarantee prior to the expiration of the 45-day cure period, an automatic early maturity event will occur and substantially all of the Company's outstanding indebtedness would be payable on demand. Additionally, other non-financial requirements due on April 30, 2026 were not met, and the debenture holders have the ability to declare an event of early maturity. As of the date of the issuance of these financial statements, the debenture holders have not declared an early maturity event. Nonetheless, the outstanding principal balance of the PortoCem Debentures has been presented as a current liability as of March 31, 2026 as the Company determined that it is not currently probable that the bank guarantee can be provided. 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. Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of March 31, 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.