# New Fortress Energy Inc. (NFE) Informational only - not investment advice. CIK: 0001749723 SIC: 4924 Natural Gas Distribution SIC breadcrumb: [Transportation, Communications, Electric, Gas, And Sanitary Services](/division/E/) > [Electric, Gas, And Sanitary Services](/major-group/49/) > [SIC 4924 Natural Gas Distribution](/industry/4924/) Latest 10-K filed: 2026-04-13 SEC page: https://www.sec.gov/edgar/browse/?CIK=1749723 Filing source: https://www.sec.gov/Archives/edgar/data/1749723/000174972326000032/nfe-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 1504037000 | USD | 2025 | 2026-04-13 | | Net income | -1831953000 | USD | 2025 | 2026-04-13 | | Assets | 10555623000 | USD | 2025 | 2026-04-13 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-04-13. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001749723.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts. | Metric | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | 97,262,000 | 112,301,000 | 189,125,000 | 451,650,000 | 1,322,810,000 | 2,368,272,000 | 2,390,605,000 | 2,358,944,000 | 1,504,037,000 | | Net income | -31,671,000 | -78,182,000 | -204,319,000 | -263,965,000 | 92,711,000 | 184,786,000 | 548,224,000 | -244,537,000 | -1,831,953,000 | | Operating income | -24,990,000 | -58,488,000 | -187,275,000 | -155,358,000 | 238,878,000 | 737,380,000 | 935,651,000 | 528,479,000 | -1,120,414,000 | | Diluted EPS | | | -1.62 | -1.71 | 0.47 | 0.93 | 2.65 | -1.26 | -6.63 | | Operating cash flow | -54,892,000 | -93,227,000 | -234,261,000 | -125,566,000 | 84,770,000 | 355,111,000 | 818,579,000 | 602,206,000 | -583,382,000 | | Capital expenditures | 28,727,000 | 181,151,000 | 377,051,000 | 156,995,000 | 669,348,000 | 1,174,008,000 | 2,919,768,000 | 2,130,641,000 | 650,811,000 | | Dividends paid | | 0.00 | 0.00 | 33,742,000 | 88,756,000 | 99,050,000 | 723,962,000 | 65,310,000 | 3,472,000 | | Assets | | 699,402,000 | 1,123,814,000 | 1,908,091,000 | 6,876,492,000 | 7,705,082,000 | 10,513,437,000 | 12,923,225,000 | 10,555,623,000 | | Liabilities | | 416,755,000 | 736,490,000 | 1,533,005,000 | 4,882,438,000 | 6,263,223,000 | 8,735,661,000 | 10,831,954,000 | 10,245,992,000 | | Stockholders' equity | | | 84,805,000 | 366,959,000 | 1,791,575,000 | 1,289,820,000 | 1,640,001,000 | 1,878,041,000 | 182,647,000 | | Cash and cash equivalents | | 78,301,000 | 27,098,000 | 601,522,000 | 187,509,000 | 675,492,000 | 155,414,000 | 492,881,000 | 226,453,000 | | Free cash flow | -83,619,000 | -274,378,000 | -611,312,000 | -282,561,000 | -584,578,000 | -818,897,000 | -2,101,189,000 | -1,528,435,000 | -1,234,193,000 | ### Ratios ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported. | Metric | 2017 | 2018 | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Net margin | -32.56% | -69.62% | -108.03% | -58.44% | 7.01% | 7.80% | 22.93% | -10.37% | -121.80% | | Operating margin | -25.69% | -52.08% | -99.02% | -34.40% | 18.06% | 31.14% | 39.14% | 22.40% | -74.49% | | Return on equity | | | -240.93% | -71.93% | 5.17% | 14.33% | 33.43% | -13.02% | | | Return on assets | | -11.18% | -18.18% | -13.83% | 1.35% | 2.40% | 5.21% | -1.89% | -17.36% | | Liabilities / equity | | | 8.68 | 4.18 | 2.73 | 4.86 | 5.33 | 5.77 | 56.10 | | Current ratio | | 0.38 | 2.06 | 3.99 | 1.04 | 0.98 | 0.58 | 0.92 | 0.15 | ## Quarterly Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-14. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001749723.json. Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived. | Quarter | End date | Revenue | Net income | Diluted EPS | Method | | --- | --- | ---: | ---: | ---: | --- | | 2022-Q2 | 2022-06-30 | | | -0.81 | reported discrete quarter | | 2022-Q3 | 2022-09-30 | | | 0.29 | reported discrete quarter | | 2023-Q1 | 2023-03-31 | | | 0.71 | reported discrete quarter | | 2023-Q2 | 2023-03-31 | | 151,566,000 | | reported discrete quarter | | 2023-Q2 | 2023-06-30 | 561,345,000 | | 0.58 | reported discrete quarter | | 2023-Q3 | 2023-06-30 | | 120,100,000 | | reported discrete quarter | | 2023-Q3 | 2023-09-30 | 514,462,000 | | 0.30 | reported discrete quarter | | 2023-Q4 | 2023-12-31 | 758,358,000 | 214,872,000 | | derived Q4 = FY annual - nine-month YTD | | 2024-Q1 | 2024-03-31 | 690,321,000 | 56,670,000 | 0.26 | reported discrete quarter | | 2024-Q2 | 2024-03-31 | | 56,670,000 | | reported discrete quarter | | 2024-Q2 | 2024-06-30 | 428,006,000 | | -0.44 | reported discrete quarter | | 2024-Q3 | 2024-06-30 | | -86,860,000 | | reported discrete quarter | | 2024-Q3 | 2024-09-30 | 567,535,000 | | 0.03 | reported discrete quarter | | 2024-Q4 | 2024-12-31 | 678,998,000 | -223,510,000 | | derived Q4 = FY annual - nine-month YTD | | 2025-Q1 | 2025-03-31 | 470,536,000 | -197,373,000 | -0.73 | reported discrete quarter | | 2025-Q2 | 2025-03-31 | | -197,373,000 | | reported discrete quarter | | 2025-Q2 | 2025-06-30 | 301,692,000 | | -2.02 | reported discrete quarter | | 2025-Q3 | 2025-06-30 | | -556,827,000 | | reported discrete quarter | | 2025-Q3 | 2025-09-30 | 327,367,000 | | -1.07 | reported discrete quarter | | 2025-Q4 | 2025-12-31 | 404,442,000 | -784,397,000 | | derived Q4 = FY annual - nine-month YTD | | 2026-Q1 | 2026-03-31 | 226,953,000 | -400,604,000 | -1.40 | reported discrete quarter | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance - [MSPUS](/indicator/MSPUS/): Median Sales Price of Houses Sold for the United States - [HSN1F](/indicator/HSN1F/): New One Family Houses Sold: United States - [RHORUSQ156N](/indicator/RHORUSQ156N/): Homeownership Rate in the United States - [TTLCONS](/indicator/TTLCONS/): Total Construction Spending: Total Construction in the United States - [RRVRUSQ156N](/indicator/RRVRUSQ156N/): Rental Vacancy Rate in the United States - [TOTALSL](/indicator/TOTALSL/): Total Consumer Credit Owned and Securitized - [REVOLSL](/indicator/REVOLSL/): Revolving Consumer Credit Owned and Securitized - [DRCCLACBS](/indicator/DRCCLACBS/): Delinquency Rate on Credit Card Loans, All Commercial Banks - [GDP](/indicator/GDP/): Gross Domestic Product - [GPDI](/indicator/GPDI/): Gross Private Domestic Investment - [GCE](/indicator/GCE/): Government Consumption Expenditures and Gross Investment - [PCEC](/indicator/PCEC/): Personal Consumption Expenditures - [NETEXP](/indicator/NETEXP/): Net Exports of Goods and Services - [GFDEBTN](/indicator/GFDEBTN/): Federal Debt: Total Public Debt - [GFDEGDQ188S](/indicator/GFDEGDQ188S/): Federal Debt: Total Public Debt as Percent of Gross Domestic Product - [FYFSD](/indicator/FYFSD/): Federal Surplus or Deficit - [FGRECPT](/indicator/FGRECPT/): Federal Government Current Receipts - [FGEXPND](/indicator/FGEXPND/): Federal Government: Current Expenditures - [MANEMP](/indicator/MANEMP/): All Employees, Manufacturing - [USCONS](/indicator/USCONS/): All Employees, Construction - [USTRADE](/indicator/USTRADE/): All Employees, Retail Trade - [USFIRE](/indicator/USFIRE/): All Employees, Financial Activities - [USGOVT](/indicator/USGOVT/): All Employees, Government - [AWHAETP](/indicator/AWHAETP/): Average Weekly Hours of All Employees, Total Private - [DGORDER](/indicator/DGORDER/): Manufacturers' New Orders: Durable Goods - [NEWORDER](/indicator/NEWORDER/): Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft - [BUSINV](/indicator/BUSINV/): Total Business Inventories - [EXPGS](/indicator/EXPGS/): Exports of Goods and Services - [IMPGS](/indicator/IMPGS/): Imports of Goods and Services - [IR](/indicator/IR/): Import Price Index (End Use): All Commodities - [PPIFIS](/indicator/PPIFIS/): Producer Price Index by Commodity: Final Demand ## Latest quarter (10-Q) Latest 10-Q source: https://www.sec.gov/Archives/edgar/data/1749723/000174972326000062/nfe-20260331.htm Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high Filing date: 2026-05-14 Report date: 2026-03-31 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 Faci [Excerpt truncated for page length; source filing is linked above.] ## Latest 10-K MD&A Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high Item 7.    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 Annual Report on Form 10-K (“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 comparison of the years ended December 31, 2024 and 2023 can be found in our Annual Report on Form 10-K for the year ended December 31, 2024 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying Management’s Discussion and Analysis of Financial Condition and Results of Operations gives effect to the restatement of our previously issued audited consolidated financial statements for the years ended December 31, 2024 and December 31, 2023 and our previously issued unaudited consolidated financial statements for each of the interim periods ended March 31, 2024, June 30, 2024, September 30, 2024, March 31, 2025, June 30, 2025, and September 30, 2025. Please refer to “—Recent Developments—Restatement of Previously Issued Financial Statements” and Note 1 and Note 33 of our notes to the consolidated financial statements included in this Annual Report for further discussion. The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual 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 Annual 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 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. Additionally, the Company did not make interest and 67 Table of Contents principal payments due in the fiscal quarter ended March 31, 2026 on the 2026 Notes and the 2029 Notes, which will result in events of default under each series of notes if not cured within 30 days. 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 will receive 100% of the common equity interests of BrazilCo, the parent company of NFE’s Brazil business, in exchange for the retirement of all New 2029 Notes. 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. Upon completion of 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 may be required to pursue alternative restructuring initiatives, including possible in-court proceedings, which could have a material adverse impact on stakeholders. For further discussion of the RSA, the Restructuring Plans and the Restructuring Transaction, see “Items 1 and 2. Business and Properties—Planned Debt Restructuring.” 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. On May 14, 2025, we completed the sale of our Jamaica business, including operations at the LNG import terminal in Montego Bay, the offshore floating storage and regasification terminal in Old Harbour and the 150 MW Combined Heat 68 Table of Contents and Power Plant in Clarendon, along with the associated infrastructure (the “Jamaica Business”). We received cash proceeds of approximately $961.9 million, with an additional $58.0 million of proceeds held in escrow to be returned to us based on the terms of the sale agreement. The proceeds were partially used to repay all outstanding South Power Bonds of $227.2 million and certain transaction costs. Our Current Operations – Terminals and Infrastructure Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including, the Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility, each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers. San Juan Facility Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and industrial end-user customers in Puerto Rico. In 2023, we entered into agreements for the installation and operation of approximately 350 MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas. Our customer was contracted by the U.S. Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 350 MW of duel-fuel power generation using our gas supply in less than 180 days. In March 2024, our contract to provide emergency power services to support the grid stabilization project was terminated, and we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA. In December 2025, we entered into a settlement agreement, pursuant to which the Company will receive a total of $142.0 million as equitable adjustment related to the early termination of our contract to provide emergency power services. We expect to receive the balance in the first half of 2026. 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 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. In 2023, our wholly-owned subsidiary, Genera PR LLC (“Genera”), was awarded a 10-year contract for the operation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and improving reliability of power generation in Puerto Rico. The service period under the contract commenced on July 1, 2023, and we receive an annual management fee for the services provided. La Paz Facility In 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 69 Table of Contents 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 2.05GW 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 exposures 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. Certain vessels are currently chartered to third parties under long-term arrangements and are included in the Energos Formation Transaction (defined below); such vessels are included in our Ships segment. At the expiration of third party charters of these vessels, we plan to utilize these vessels for our own operational purposes. Vessels we operate at our terminal operations or that we decide to sub-charter are included in our Terminals and Infrastructure segment. In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of eleven vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos. 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 70 Table of Contents million. This transaction resulted in the sale of these vessels that were previously accounted for as a failed sale leaseback. Upon closing of the transaction, the Company derecognized these vessels with a net book value of $667.0 million from Property, plant and equipment, derecognized debt of $734.2 million, and recognized a gain of $217.1 million. The Company will also no longer recognize 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. 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 first half 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 71 Table of Contents 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 2026. 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. 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 “Items 1 and 2. Business and Properties—Planned Debt Restructuring.” Restatement of Previously Issued Financial Statements As previously reported on the Company’s Current Report on Form 8-K filed on March 17, 2026, during the preparation of the Company’s consolidated financial statements for the year ended December 31, 2025, the Company identified errors in its historical consolidated statements of cash flows and determined that adjustments are required to previously issued audited consolidated financial statements. Accordingly, the Company is restating its previously issued audited consolidated financial statements for the years ended December 31, 2024 and December 31, 2023. During the periods covered by the financial statements, the Company delayed payments to certain vendors on certain significant development projects, which allowed the Company to improve its working capital and liquidity. Payments for capital expenditures significantly outside of a vendor’s customary payment terms should be classified as financing activities, as opposed to investing activities, which is how these payments were presented in the previously issued financial statements. In connection with the restatement, the Company is also correcting unrelated errors identified in prior periods. Additionally, the Company’s unaudited consolidated financial statements as of and for each of the interim periods ended March 31, 2024, June 30, 2024, September 30, 2024, March 31, 2025, June 30, 2025, and September 30, 2025 are being restated to correct the classification of capital expenditures paid outside of customary payment terms, as well as to correct other unrelated errors. Refer to Note 1 and Note 33 of our notes to the consolidated financial statements included in this Annual Report 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 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 72 Table of Contents 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. 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. Factors Impacting Comparability of Our Financial Results Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons: •Our historical results of operations include our Jamaica Business. In May 2025, we completed the sale of our Jamaica Business, and we no longer include the results of operations of the Montego Bay Facility and Old Harbour Facility in our financial statements. Our results of operations include the cost of operating FLNG 1. We placed our first Fast LNG project into service in the fourth quarter of 2024. This project represents our largest ever capital project and placing the asset into service from an accounting perspective that has significantly increased the depreciation recognized in the current period; such depreciation also impacts the cost of LNG delivered from the FLNG facility. This also increased interest expense as we are no longer able to capitalize borrowing costs associated this development. 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 73 Table of Contents 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. 74 Table of Contents Results of Operations – Three Months Ended December 31, 2025 compared to Three Months Ended September 30, 2025 (As Restated) and Year Ended December 31, 2025 compared to Year Ended December 31, 2024 (As Restated) Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management’s evaluation of the overall performance of our operating assets. Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business. The tables below present our segment information for the three months ended December 31, 2025 and September 30, 2025, and for the year ended December 31, 2025 and December 31, 2024: Three Months Ended December 31, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other(3) Consolidated Total revenues $ 379,067  $ 16,677  $ 395,744  $ —  $ 395,744  Cost of sales(1) 211,157  —  211,157  —  211,157  Vessel operating expenses(4) 690  3,363  4,053  —  4,053  Operations and maintenance(4) 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  Three Months Ended September 30, 2025 (As Restated) (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other(3) Consolidated Total revenues $ 306,309  $ 25,602  $ 331,911  $ —  $ 331,911  Cost of sales(1) 196,908  —  196,908  —  196,908  Vessel operating expenses(4) 1,940  5,357  7,297  —  7,297  Operations and maintenance(4) 57,301  —  57,301  —  57,301  Segment Operating Margin $ 50,160  $ 20,245  $ 70,405  $ —  $ 70,405  75 Table of Contents Three Months Ended September 30, 2025 (As Restated) (in thousands of $) Consolidated Gross margin (GAAP) $ 21,075  Depreciation and amortization 49,330  Consolidated Segment Operating Margin (Non-GAAP) $ 70,405  Year Ended December 31, 2025 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other(2) Consolidated Total revenues $ 1,384,693  $ 119,344  $ 1,504,037  $ —  $ 1,504,037  Cost of sales(1) 918,603  —  918,603  —  918,603  Vessel operating expenses(4) 4,407  22,187  26,594  —  26,594  Operations and maintenance(4) 218,511  —  218,511  —  218,511  Segment Operating Margin $ 243,172  $ 97,157  $ 340,329  $ —  $ 340,329  Year Ended December 31, 2025 (in thousands of $) Consolidated Gross margin (GAAP) $ 136,821  Depreciation and amortization 203,508  Consolidated Segment Operating Margin (Non-GAAP) $ 340,329  Year Ended December 31, 2024 (As Restated) (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other(2) Consolidated Total revenues(5) $ 2,041,580  $ 170,587  $ 2,212,167  $ 146,777  $ 2,358,944  Cost of sales(1) 1,065,181  —  1,065,181  —  1,065,181  Vessel operating expenses(4) —  33,372  33,372  —  33,372  Operations and maintenance(4) 170,763  —  170,763  —  170,763  Deferred earnings from contracted sales(3) 150,000  —  150,000  (150,000) —  Segment Operating Margin $ 955,636  $ 137,215  $ 1,092,851  $ (3,223) $ 1,089,628  Year Ended December 31, 2024 (As Restated) (in thousands of $) Consolidated Gross margin (GAAP) $ 930,837  Depreciation and amortization 158,791  Consolidated Segment Operating Margin (Non-GAAP) $ 1,089,628  (1)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive (Loss) Income. (2)For the year ended December 31, 2024, Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $150.0 million which were recognized during the third and fourth quarters of 2024. (3)Deferred earnings from contracted sales represent forward sales transactions that were contracted in the second and third quarters of 2024 and prepayment for these sales was received. Revenue has been recognized in the Consolidated Statements of Operations and Comprehensive (Loss) Income during the third and fourth quarters of 2024. (4)Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin as defined under GAAP. 76 Table of Contents (5)For the year ended December 31, 2024, Consolidation and Other adjusts for $3.2 million in amortization of intangible assets recognized upon acquisition of certain vessels with in-place leases, which was recorded in Vessel charter revenue; such amortization is excluded from Total Segment Operating Margin reviewed by our CODM. Terminals and Infrastructure Segment Three Months Ended, (in thousands of $) December 31, 2025 September 30, 2025 (As Restated) Change Total revenues $ 379,067  $ 306,309  $ 72,758  Cost of sales (exclusive of depreciation and amortization) 211,157  196,908  14,249  Vessel operating expenses 690  1,940  (1,250) Operations and maintenance 48,866  57,301  (8,435) Segment Operating Margin $ 118,354  $ 50,160  $ 68,194  Year Ended, (in thousands of $) December 31, 2025 December 31, 2024 (As Restated) Change Total revenues $ 1,384,693  $ 2,041,580  $ (656,887) Cost of sales (exclusive of depreciation and amortization) 918,603  1,065,181  (146,578) Vessel operating expenses 4,407  —  4,407  Operations and maintenance 218,511  170,763  47,748  Deferred earnings from contracted sales —  150,000  (150,000) Segment Operating Margin $ 243,172  $ 955,636  $ (712,464) Total revenue Total revenue for the Terminals and Infrastructure Segment increased by $72.8 million for the three months ended December 31, 2025 as compared to the three months ended September 30, 2025. The increase was primarily driven by cargo sales, contract settlement, and power trading revenue, offset by lower volumes delivered to our terminals. The average Henry Hub index pricing used to invoice our downstream customers increased by 15% for the three months ended December 31, 2025 as compared to the three months ended September 30, 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 recognized $69.4 million of revenue from cargo sales in the three months ended December 31, 2025. No cargo sales revenue was recognized in the three months ended September 30, 2025. •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. Revenue recognized for the delivery of power under these PPAs in fourth quarter of 2025 increased from $93.9 million during the three months ended September 30, 2025 to $109.7 million during the three months ended December 31, 2025. •The increases are partially offset by lower volumes delivered to our downstream terminal customers at the San Juan and Mexico facilities, primarily due to repairs and maintenance at our customers’ facilities and lower power generation by these power facilities. Total volumes delivered decreased from 10.7 TBtu in the third quarter of 2025 to 6.4 TBtu in the fourth quarter of 2025 As a result, revenue decreased by $67.8 million at the San Juan and 77 Table of Contents the Mexico facilities. This decrease includes lower expected capacity payments in Mexico of $18.0 million attributable to lower availability of our La Paz Power Plant during the fourth quarter of 2025. •The third-party vessel charter revenue decreased by $14.7 million due to the sale of certain vessels to Energos during the fourth quarter of 2025. Total revenue for the Terminals and Infrastructure Segment decreased by $656.9 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024, and segment revenue was impacted by the following in 2025: •For the year ended December 31, 2024, we recognized $295.6 million of income from the novation of an LNG supply contract, of which $235.6 million was recognized as segment revenue. Only $6.4 million of novation income was recognized in the year ended December 31, 2025 related to the accretion of expected payments under the novated LNG supply contract. •For the year ended December 31, 2025, volumes delivered to downstream customers were 45.1 TBtu as compared to 81.3 TBtu for the year ended December 31, 2024. The lower volumes in 2025 were primarily attributable to the termination of the grid stabilization project in the first quarter of 2024 and the sale of our Jamaica Business in May 2025. ◦In Jamaica, we delivered 9.4 TBtu from our Montego Bay Facility and Old Harbour Facility in 2025, compared to 26.5 TBtu during the year ended December 31, 2024, which resulted in a reduction of revenue of $216.4 million in 2025. ◦Revenue from the San Juan Facility in Puerto Rico decreased by $541.7 million in 2025, primarily due to the termination of the grid stabilization project, partially offset by $74.8 million revenue recognized from the settlement contract related to the termination. ◦During 2024, we recognized an incentive fee of $15.7 million as incentive fees under our subsidiary Genera’s operations and maintenance contract with PREPA. No such incentive fees were earned during 2025. In 2025, our revenue decreased by $14.8 million due to lower costs that were passed through to our customer under Genera’s operations and maintenance contract. ◦Lastly, revenue decreased by $14.4 million due to sale of our Miami Facility in 2024. The decrease in revenue for the year ended December 31, 2025 was partially offset by an increase due to the following: •Revenue from cargos sales increased by $75.4 million for the year ended December 31, 2025, compared with the year ended December 31, 2024. •Starting in the third quarter of 2025, we partnered with a local energy trader to supply the power required under power purchase agreements in Brazil while the Barcarena Power Plant is being commissioned. Revenue recognized for the delivery of power under these power purchase agreements during the second half of 2025 was $203.6 million. •During 2025, we entered into sub-charter agreements for Energos Eskimo, Energos Winter, and Energos Freeze, and recognized additional vessel charter revenues of $29.0 million during the year ended December 31, 2025, which is included in our Terminals and Infrastructure segment. •The average Henry Hub index pricing used to invoice our downstream customers increased by 51% for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Cost of sales Cost of sales includes the procurement of feed gas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. We source LNG and natural gas from third parties and our own liquefaction facilities, including our Fast LNG unit which was placed into service in the fourth quarter of 2024. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our liquefaction facilities are also included in Cost of sales. 78 Table of Contents 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 $14.2 million for the three months ended December 31, 2025 as compared to the three months ended September 30, 2025. The increase was primarily driven by increases in cost of cargo sales of $54.3 million as there were no cargos sales during the three months ended September 30, 2025, which were partially offset by a decrease due to lower volumes delivered. We delivered 40% lower volumes to our customers during the three months ended December 31, 2025 resulting in a decrease in cost of LNG consumed by $44.2 million. Our cost of acquiring and producing LNG decreased to $8.58 per MMBtu for the three months ended December 31, 2025 from $9.40 per MMBtu for the three months ended September 30, 2025. Cost of sales decreased by $146.6 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024, which was attributable to the following activity: •We delivered 45% less volume to our downstream terminal customers in the current year compared to 2024, principally due to the sale of our Jamaica Business, which resulted in a $122.7 million decrease in our LNG cost of sales. In addition, cost of LNG delivered at our Puerto Rico operations decreased by $103.4 million in 2025 compared to 2024 due to lower volumes delivered in 2025, primarily as a result of termination of our customer’s grid stabilization project in the first quarter of 2024. •Vessel costs decreased by $53.6 million, for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to reduced number of vessels chartered in our fleet. We assigned vessels used in the Jamaica Business to the buyer, and we redelivered certain vessels after their charters ended in the 2025. •We recognized payroll and other operating costs of $80.3 million to provide services under Genera’s operations and maintenance contract for the year ended December 31, 2025 compared to $100.2 million for the year ended December 31, 2024; these costs are passed onto PREPA. The decrease in cost of sales for the year ended December 31, 2025 as compared to the year ended December 31, 2024 was offset by the following: •Although the volumes delivered decreased, our cost of LNG increased to $8.93 per MMBtu for the year ended December 31, 2025 compared to $7.20 per MMBtu for the year ended December 31, 2024. The increase was primarily driven by higher gas prices. The average Henry Hub index pricing increased by 51% for the year ended December 31, 2025 as compared to the year ended December 31, 2024. •We incurred $89.7 million cost of sales in 2025 related to the delivery of power under power purchase agreements from the Barcarena Power Plant. No such costs were incurred in 2024. •Cost of cargo sales increased by $47.2 million in 2025 compared to 2024, reflecting less favorable pricing on certain cargo purchases. •Higher costs incurred due to increased volumes delivered from our La Paz Facility. The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 2025 and December 31, 2024 was $8.35 per MMBtu and $6.90 per MMBtu, respectively. 79 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. We incurred $4.4 million of vessel operating expenses for the year ended December 31, 2025. No such costs were incurred in this segment in 2024. Vessel operating expenses were immaterial to our results of operations for the three months ended December 31, 2025 and September 30, 2025. Operations and maintenance Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance decreased by $8.4 million for the three months ended December 31, 2025 as compared to the three months ended September 30, 2025. In November 2025, we completed a transaction with Energos, that resulted in sale of four vessels. Following the transaction, we ceased incurring operating costs for three of the vessels that were part of our Terminals and Infrastructure segment. In addition, our operating expenses decreased due to the expiration of an operating lease, reduction in port fees, and decreased spare parts usage at our terminals. Operations and maintenance increased by $47.7 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase is primarily due to Fast LNG unit and the Santa Catarina Facility that were placed in service at the end of 2024. The increase was also driven by higher vessel charter costs as more vessels were deployed in our terminal operations during 2025. These impacts were partially offset by the sale of our Jamaica Business in May 2025. Deferred earnings from contracted sales During 2024, we completed forward sales and received prepayments from the buyers of $150.0 million. The prepayments were based on the fair market value of these sales as compared to our supply cost, and our CODM includes these results in this evaluation of Terminals and Infrastructure operations. Revenue for these sales were recognized in our Consolidated Statements of Operations and Comprehensive (Loss) Income in 2024, and as such, these deferred earnings do not impact the total segment operating margin recognized for the year ended December 31, 2024. Ships Segment Three Months Ended, (in thousands of $) December 31, 2025 September 30, 2025 (As Restated) Change Total revenues $ 16,677  $ 25,602  $ (8,925) Vessel operating expenses 3,363  5,357  (1,994) Segment Operating Margin $ 13,314  $ 20,245  $ (6,931) Year Ended, (in thousands of $) December 31, 2025 December 31, 2024 (As Restated) Change Total revenues $ 119,344  $ 170,587  $ (51,243) Vessel operating expenses 22,187  33,372  (11,185) Segment Operating Margin $ 97,157  $ 137,215  $ (40,058) Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of December 31, 2025, one vessel included in the Energos Formation Transaction was under a third-party charter and is included in this segment. 80 Table of Contents Total revenue Total revenue for the Ships segment decreased by $8.9 million from the three months ended September 30, 2025 to the three months ended December 31, 2025. In November 2025, we completed a transaction with Energos, pursuant to which we early terminated the long-term charter agreements with Energos for certain vessels, including Energos Igloo, which was included in the Ships segment at September 30, 2025. This transaction resulted in a sale of Energos Igloo to Energos and a reduction in charter revenue for the three months ended December 31, 2025 compared to the three months ended September 30, 2025. Total revenue for the Ships segment decreased by $51.2 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of certain vessels included in the transaction, and as such, we continue to recognize revenue from the charter of these vessels to third parties. We excluded such vessels from the Ships segment and included them in our Terminals and Infrastructure segment as certain third-party charters expired and we began to use the vessels in our own operations during the year ended December 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 decreased by $2.0 million from the three months ended September 30, 2025 to the three months ended December 31, 2025. Vessel operating expenses decreased by $11.2 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The vessel operating expenses were lower during the three months and the year ended December 31, 2025 as all vessels aside from Nusantara Regas Satu were either utilized in our terminal operations following the conclusion of their third party charters, or were sold as part of the vessel sale transaction to Energos, as discussed above. 81 Table of Contents Other operating results Three Months Ended, Year Ended, (in thousands of $) December 31, 2025 September 30, 2025 (As Restated) Change December 31, 2025 December 31, 2024 (As Restated) Change Selling, general and administrative $ 112,596  $ 86,467  $ 26,129  $ 307,442  $ 293,378  $ 14,064  Transaction and integration costs 54,792  19,679  35,113  161,756  12,279  149,477  Depreciation and amortization 44,997  49,330  (4,333) 203,508  158,791  44,717  Asset impairment expense 732,954  4,782  728,172  860,865  16,494  844,371  (Gain) loss on sale (199,944) —  (199,944) (670,938) 80,207  (751,145) Goodwill impairment expense 15,938  —  15,938  598,110  —  598,110  Total operating expenses 761,333  160,258  601,075  1,460,743  561,149  899,594  Operating (loss) income (629,664) (89,853) (539,811) (1,120,414) 528,479  (1,648,893) Interest expense 192,929  198,218  (5,289) 777,845  316,337  461,508  Other (income) expense, net 5,934  (30,566) 36,500  (147,593) 116,308  (263,901) Loss on extinguishment of debt, net (850) —  (850) 19,937  270,063  (250,126) (Loss) income before income taxes (827,676) (257,505) (570,171) (1,770,603) (174,229) (1,596,374) Tax provision 19,386  5,496  13,890  61,350  70,308  (8,958) Net loss $ (847,062) $ (263,001) $ (584,061) $ (1,831,953) $ (244,537) $ (1,587,416) Selling, general and administrative Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors, and screening costs for projects that are in initial stages and development is not yet probable. Selling, general and administrative increased by $26.1 million for the three months ended December 31, 2025 as compared to the three months ended September 30, 2025. During the three months ended December 31, 2025, we recorded $45.6 million contingent losses related to certain legal proceedings compared to $18.6 million loss recorded during the three months ended September 30, 2025. Selling, general and administrative increased by $14.1 million for the year ended December 31, 2025, compared to the year ended December 31, 2024. The increase was primarily due to provision for certain legal matters of $64.2 million with our customers and vendors. In addition, legal and professional fees increased by $8.5 million, mostly attributable to certain litigation and arbitration proceedings. These increases were largely offset by a $35.9 million reduction of share-based compensation expense in 2025 primarily due to the vesting of a large number of restricted share units at the beginning of 2025. Screening costs for development projects decreased by $11.5 million due to lower activity to develop potential projects during 2025. Lastly, our bad debt expense decreased by $14.1 million in 2025, primarily due to a reversal of an allowance for bad debt as a result of a settlement agreement entered with our customer as discussed above. Transaction and integration costs We incurred transaction and integration costs of $54.8 million and $19.7 million, respectively, during the three months ended December 31, 2025 and September 30, 2025, which is primarily comprised of professional and consulting fees relating to our debt restructuring process, as well as costs incurred for certain debt amendments. 82 Table of Contents We incurred $161.8 million of transaction and integration costs during the year ended December 31, 2025. In addition to the professional and consulting fees related to our debt restructuring, we incurred $71.1 million of transaction costs directly attributable to the sale of the Jamaica Business, which included fees associated with novating a vessel charter to the buyer and contingent fees due to our advisors. Remaining transaction and integration costs relate to legal fees and other third party costs incurred in connection with amendments to credit agreements, which were accounted for as modifications. The transaction and integration costs of $12.3 million during the year ended December 31, 2024 primarily relate to legal fees and other third party costs incurred by the Company in connection with the amendments of credit agreements, which were accounted for as modifications. Depreciation and amortization Depreciation and amortization decreased by $4.3 million for the three months ended December 31, 2025 as compared to the three months ended September 30, 2025. The decrease was primarily attributable to the sale of certain vessels to Energos during the fourth quarter of 2025 as discussed above. Depreciation and amortization increased by $44.7 million for the year ended December 31, 2025 as compared to the year ended December 31, 2024. The increase in depreciation expense resulted from the Fast LNG project and the Santa Catarina Facility being placed into service in December 2024, and was partially offset by a reduction following the sale of certain turbines and equipment to PREPA in the first half of 2024, and the sale of our Jamaica Business in May 2025. Asset impairment expense 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. During the three months ended September 30, 2025, we determined that it was not probable that we would pursue development of certain projects and recognized an impairment charge of $4.8 million relating to costs incurred on these development projects. During the year ended December 31, 2025, we recognized an impairment charge of $860.9 million, principally related to the Fast LNG project and the ZeroParks hydrogen project discussed above, the Lakach deepwater project and the development project in Pennsylvania. During the year ended December 31, 2024, we recognized an impairment expense of $16.5 million related to the sale of our Miami Facility. 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 for the three months ended September 30, 2025. During the year ended December 31, 2025, we recognized an impairment of goodwill of $582.2 million in our Terminals and Infrastructure segment, primarily as a result of (i) the significant increase in the WACC 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. Following the impairments recognized in the Terminals and Infrastructure and Ships segments described above, the remaining goodwill has been fully impaired. There was no goodwill impairment expense recognized for the year ended December 31, 2024. (Gain) loss on sale 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 83 Table of Contents agreements with Energos for certain vessels and novated associated sub-charter agreements for these vessels to Energos, in exchange for cash consideration of $150.0 million. The Company recognized a gain of $217.1 million from the transaction. For the year ended December 31, 2025, the Company recorded a gain of $670.9 million. In addition to the vessel sale transaction discussed above, in May 2025, the Company completed the sale of its Jamaica Business, and recognized a gain of $453.8 million from the sale. During the year ended December 31, 2024, the Company recognized a loss of $80.2 million from the sale of turbines and related equipment to the PREPA. Interest expense Interest expense decreased by $5.3 million for the three months ended December 31, 2025 as compared to the three months ended September 30, 2025, primarily due to lower debt resulting from the vessel sale transaction during the fourth quarter of 2025. Interest expense increased by $461.5 million during the year ended December 31, 2025 as compared to the year ended December 31, 2024, primarily due to higher debt balances outstanding as well as increased borrowing rates. In addition, we also capitalized lower interest expense of $339.6 million for the year ended December 31, 2025 compared to $501.9 million for the year ended December 31, 2024, as the Fast LNG project and Santa Catarina Facility were placed into service at the end of 2024. Other expense (income), net Other expense, net and other income, net was $5.9 million and $30.6 million for the three months ended December 31, 2025 and September 30, 2025, respectively. Other income, net and other expense, net was $147.6 million and $116.3 million for the year ended December 31, 2025 and December 31, 2024, respectively. Other income (expense), net for the third and fourth quarters of 2025, as well as for the years ended 2025 and 2024, 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. The losses were partially offset by interest income, and realized and unrealized gains on foreign currency derivative contracts. The interest income was derived largely from the restricted cash for our development projects in Brazil. Loss on extinguishment of debt, net The Company had no material extinguishment of debt for the three months ended December 31, 2025 and September 30, 2025. During 2025, we reduced the available capacity under our Revolving Facility by $270.0 million and recognized $10.6 million of loss on extinguishment of debt, which represents the write-off of unamortized deferred financing costs. We also recognized $5.9 million of loss on extinguishment of debt related to the repayment of the South Power Bonds in conjunction with closing of the sale of our Jamaica Business. Additionally, we made a partial repayment of the Term Loan A using proceeds from the sale and incurred a partial extinguishment loss of $3.0 million. During 2024, we repaid all of the 2025 Notes and a portion of the 2026 Notes and 2029 Notes, and recognized as a loss on extinguishment of debt totaling $235.4 million. In Brazil, we repaid the PortoCem Bridge Loan with proceeds from the PortoCem Debenture issuance and recorded a loss on extinguishment of $25.0 million. In addition, during the first quarter of 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes. During the same period, we also recognized a premium over the repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes. Tax provision We recognized a tax provision of $61.4 million for the year ended December 31, 2025 compared to a tax provision of $70.3 million for the year ended December 31, 2024. For the year ended December 31, 2025, the tax provision was primarily driven by valuation allowance against deferred tax assets related to losses in U.S. operations and losses generated by foreign operations in Brazil and Mexico. 84 Table of Contents Liquidity and Capital Resources Cash Flows The following table summarizes the changes to our cash flows for the year ended December 31, 2025 and 2024, respectively: Year Ended December 31, (in thousands) 2025 2024 (as Restated) Change Cash flows from: Operating activities $ (583,382) $ 602,206  $ (1,185,588) Investing activities 465,763  (1,584,054) 2,049,817  Financing activities (543,640) 1,718,511  (2,262,151) Net (decrease) increase in cash, cash equivalents, and restricted cash $ (661,259) $ 736,663  $ (1,397,922) Cash (used in) / provided by operating activities Our cash flow used in operating activities was $583.4 million for the year ended December 31, 2025, which decreased by $1,185.6 million from cash provided by operating activities of $602.2 million for the year ended December 31, 2024. Our net loss for the year ended December 31, 2025, when adjusted for non-cash items, increased by $1.2 billion from the year ended December 31, 2024. Cash outflows during the year ended December 31, 2025 includes significant interest payments resulting from both higher amounts of outstanding debt and increased interest rates. Cash paid for interest, excluding capitalized interest, during 2025 totaled approximately $352.2 million. Additionally, we have incurred significant professional and consulting fees relating to our capital restructuring process. We have recognized reduced cash flows following the sale of our Jamaica Business. Following the sale of the Jamaica Business, we continue to incur operational and administrative costs that supported all of our operations, including Jamaica. Additionally, our first FLNG unit was placed in service at the end of 2024, and we have incurred increased operational and maintenance costs as we optimize our LNG production process. Cash provided by / (used in) investing activities Our cash flow provided by investing activities was $465.8 million for the year ended December 31, 2025, which increased by $2.0 billion from cash used in investing activities of $1.6 billion for the year ended December 31, 2024. Cash inflows from investing activities during the year ended December 31, 2025 were primarily from proceeds of $961.9 million from the sale of the Jamaica Business and $150.0 million from the sale of Energos vessels. Cash inflows were offset by $908.8 million of capital expenditures of which $257.9 million was paid significantly beyond our vendors customary payment terms, and as such, is presented as a financing activity. Capital expenditures were used for continued construction of the PortoCem Power Plant and the Puerto Sandino Facility, and for expansion projects in Puerto Rico. Cash outflows from investing activities during the year ended December 31, 2024 were primarily used for continued development of our Fast LNG project and the construction of the PortoCem Power Plant and Barcarena Power Plant. Cash outflows were offset by proceeds from the sale of assets including the sale of turbines and related equipment to PREPA, our investment in Energos, the Mazo and the Miami Facility. Cash (used in) / provided by financing activities Our cash flow used in financing activities was $543.6 million for the year ended December 31, 2025, which decreased by $2.3 billion from cash provided by financing activities of $1.7 billion for the year ended December 31, 2024. During the year ended December 31, 2025 we had total borrowings of $1.4 billion, a portion of which were used to repay the Barcarena Debentures in full. We also repaid a portion of our Revolving Facility and repaid our short-term borrowings under repurchase agreements, prior to drawing again on these facilities. In conjunction with closing the sale of the Jamaica Business, we repurchased all outstanding South Power Bonds for $227.1 million. 85 Table of Contents During the year ended December 31, 2024 we had total borrowings of $5.9 billion, with such borrowings primarily used to fund development of the Fast LNG project, Barcarena Power Plant, and PortoCem Power Plant. Such borrowings were also used to repay a portion of the 2025 Notes and various asset level financings in Puerto Rico and Brazil. We also repaid a portion of our Revolving Facility and short-term borrowings under repurchase agreements, prior to again drawing on these facilities. Contractual Obligations We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations 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) Total Year 1 Years 2 to 3 Years 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.” The amounts included in the table above are based on the total debt balance, scheduled maturities or accelerated maturities under the events of default, and interest rates in effect as of December 31, 2025 and includes certain obligations that will not be owed by us upon completion of the Restructuring Transaction. 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 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 86 Table of Contents 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 New 2029 Notes On November 6, 2024, we entered into an exchange and subscription agreement (the “Exchange and Subscription Agreement”) with certain holders (the “Supporting Holders”) of our outstanding 2026 Notes and 2029 Notes. Pursuant to the Exchange and Subscription Agreement (i) NFE Financing, an indirect subsidiary of NFE, sold to the Supporting Holders approximately $1,210.4 million aggregate principal amount of NFE Financing’s 12.000% Senior Secured Notes due 2029 (the “New 2029 Notes”) (the transactions described in clause (i), the “Subscription Transactions”) and (ii) NFE Financing issued to the Supporting Holders approximately $1,519.7 million aggregate principal amount of New 2029 Notes in a dollar-for-dollar exchange for a portion of our 2026 Notes and 2029 Notes (the transactions described in clause (ii), the “Exchange Transactions” and together with the Subscription Transactions, the “Refinancing Transactions”). NFE Financing issued $2,730.1 million aggregate principal amount of New 2029 Notes pursuant to the Refinancing Transactions. The Company utilized $886.6 million of these net proceeds from the Subscription Transactions to repay in full the outstanding aggregate principal amount and accrued interest on the 2025 Notes. The remainder of the net proceeds from the New 2029 Notes issued pursuant to the Subscription Transactions were used for general corporate purposes. Pursuant to the Exchange and Subscription Agreement, upon consummation of the Refinancing Transactions, the Supporting Holders received a commitment fee equal to either (i) 5% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in shares of Class A common stock of the Company, at a price of $8.63 per share (the “Commitment Fee Shares”), (ii) 2% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in kind in the form of additional New 2029 Notes (the “Commitment Fee Notes”), or (iii) a combination of the foregoing. The Company issued 15,700,998 Commitment Fee Shares to the Supporting Holders in satisfaction of its commitment fee obligations under the Exchange and Subscription Agreement, and $5.4 million Commitment Fee Notes were issued and included in the total New 2029 Notes issuance. The New 2029 Notes were issued pursuant to, and are governed by, an indenture (the “New 2029 Notes Indenture”). The New 2029 Notes are senior, secured obligations of NFE Financing, and interest is payable semi-annually in arrears at a rate of 12.000% per annum on May 15 and November 15 of each year, beginning on May 15, 2025. The New 2029 Notes will mature on November 15, 2029, provided that the maturity date shall be accelerated to the date that is 91 days prior to the stated maturity date of any of our other indebtedness, subject to certain exceptions as described in the New 2029 Notes Indenture, if more than $100.0 million aggregate principal amount of such other indebtedness remains outstanding on such date. NFE Financing may redeem some or all of the New 2029 Notes at redemption prices set forth in the New 2029 Notes Indenture; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. Further, upon the occurrence of certain other events, including change of control and certain distributions from our Brazil business, NFE Financing may be required to make an offer to repurchase all of the New 2029 Notes at prices specified in the New 2029 Notes Indenture. The New 2029 Notes Indenture contains default provisions that would allow these holders to accelerate the maturity date under the New 2029 Notes following the occurrence of a default by the Company or any of its subsidiaries on indebtedness for borrowed money if the principal amount of such indebtedness is equal to $10.0 million in the case of NFE Financing and $100.0 million in the case of the Company and any of its other subsidiaries unless such defaulted indebtedness has been discharged, the default has been cured or the holders have rescinded or waived the acceleration, notice or action giving rise to the event of default. NFE Financing did not make the interest payment of $163.8 million due to holders of the New 2029 Notes on November 17, 2025. An event of default under the New 2029 Notes Indenture arose on November 20, 2025, when the contractual grace period for interest payments on such notes expired. Such defaults are subject to forbearance under the RSA pursuant to which the holders have agreed, subject to certain conditions, to refrain from exercising remedies with respect to specified defaults until termination of the RSA or the closing of the Restructuring Transaction. If the Restructuring Transaction is not consummated or the RSA is terminated, the holders thereunder could accelerate the 87 Table of Contents outstanding indebtedness. Upon completion of the Restructuring Transaction contemplated under the RSA, the New 2029 Notes will no longer be outstanding. 2026 Notes In April 2021, we issued $1,500.0 million of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of each year; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2026 Notes are guaranteed, jointly and severally, on a senior secured basis by certain domestic and foreign subsidiaries. Subsequent to the Refinancing Transactions, the 2026 Notes are subject to the 2026 Supplemental Indenture. The Company did not make the interest payment of $10.4 million due to holders of the 2026 Notes on March 15, 2026. An event of default under the indenture governing the 2026 Notes will arise on April 15, 2026, when the contractual grace period for interest payments on such notes expires. Additionally, the Company has not entered into a forbearance agreement with respect to the 2026 Notes, and as a result, the holders of the 2026 Notes are not restricted from exercising remedies in connection with such event of default. Uncured events of default exist under this indenture and the credit agreements, and as such, the outstanding principal balance of the 2026 Notes has been presented as a current liability. Upon completion of the Restructuring Transaction contemplated under the RSA, the 2026 Notes will no longer be outstanding. 2029 Notes In March 2024, we issued $750.0 million of 8.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2029 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments are due until maturity on March 15, 2029. We may redeem the 2029 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The 2029 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2026 Notes. Subsequent to the Refinancing Transactions, the 2029 Notes are subject to the 2029 Supplemental Indenture. The Company did not make the interest payment of $16.6 million due to holders of the 2029 Notes on March 31, 2026. An event of default under the indenture governing the 2029 Notes will arise on April 30, 2026, when the contractual grace period for interest payments on such notes expires. Additionally, the Company has not entered into a forbearance agreement with respect to the 2029 Notes, and as a result, the holders of the 2029 Notes are not restricted from exercising remedies in connection with such event of default. Uncured events of default exist under this indenture and the credit agreements, and as such, the outstanding principal balance of the 2029 Notes has been presented as a current liability. Upon completion of the Restructuring Transaction contemplated under the RSA, the 2029 Notes will no longer be outstanding. Revolving Facility In April 2021, we entered into a credit agreement (the “Revolving Credit Agreement”) for a $200.0 million senior secured revolving credit facility (the “Revolving Facility”). The obligations under the Revolving Facility are guaranteed by certain of the Company’s subsidiaries, including those that own the Company’s offshore FLNG facility at Altamira (“FLNG 1 Project”) and FLNG 2, and are secured by substantially the same collateral securing the obligations under certain intercompany loans entered into in conjunction with the Refinancing Transactions, as well as the assets comprising the FLNG 1 Project and FLNG 2. The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate (“SOFR”) based rate plus a margin based upon usage of the Revolving Facility. The rates applicable to outstanding borrowings as of 88 Table of Contents December 31, 2025 and 2024 were 7.51% and 8.22%, respectively. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium. Through May 2024, the Revolving Facility was amended to increase the borrowing capacity to $1,000 million. The amendments did not impact the interest rate or term of the Revolving Facility, and no deferred costs were written off. As of December 31, 2025 and 2024, $660 million and $1,000 million was outstanding under the Revolving Facility, respectively. In May 2025, we entered into an amendment to the Revolving Credit Agreement to, among other things, (i) provide for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio contained therein for the fiscal quarter ended June 30, 2025, (ii) permit $270.0 million of proceeds from the sale of the Jamaica Business to be used to prepay and terminate a portion of loans and commitments currently outstanding and otherwise not require the proceeds of the sale of the Jamaica Business to be used to prepay loans and commitments, (iii) provide that the asset sale sweep mandatory prepayment will no longer apply once aggregate commitments are reduced to $550.0 million and (iv) restrict the Company from prepaying the 2026 Notes in excess of $200.0 million other than to avoid springing maturities unless any such prepayment is made using proceeds from refinancing indebtedness or capital contributions. In May 2025, we repaid $270.0 million of outstanding revolving loans under the Revolving Facility which permanently reduced the borrowing capacity to $730.0 million. Additionally, we have issued letters of credit of $69.5 million in 2025, and including the outstanding letters of credit, we have fully utilized the borrowing capacity of $729.9 million as of December 31, 2025. In November 2025, we amended our Revolving Credit Agreement to, among other things, (i) add a covenant restricting our ability to modify the New 2029 Notes Forbearance Agreement in a matter adverse to the lenders under the Revolving Credit Agreement without consent, including extensions of the forbearance period, (ii) provide a covenant holiday with respect to the consolidated first lien debt ratio, the fixed charge coverage ratio and minimum liquidity for the fiscal quarters ended September 30, 2025 with respect to the consolidated first lien debt ratio and the fixed charge coverage ratio and December 31, 2025 with respect to minimum liquidity, (iii) add a covenant restricting the ability of the Borrower to amend certain existing debt in a way that would modify the choice of law provisions of such debt, and (iv) add new events of default that would occur if the New 2029 Notes Forbearance Agreement is materially breached or does not remain in effect or if any payment is made on the outstanding principal or interest for the 2026 Notes, the 2029 Notes, the Term Loan A Credit Agreement, the Term Loan B Credit Agreement, certain intercompany agreements and the New 2029 Notes. In December 2025, we entered into an amendment to the Revolving Credit Agreement to, among other things, provide that if the Company fails to maintain the Term Loan A Forbearance Agreement and the Term Loan B Forbearance Agreement in full force and effect or materially violates its terms, an event of default would occur under the Revolving Credit Agreement. If such events of default occur, the lenders would have the right to accelerate the repayment of the outstanding principal under the Revolving Credit Agreement. If the lenders and issuing banks choose to exercise such rights under those facilities, substantially all of the Company’s outstanding indebtedness could be accelerated, and the Company may be required or compelled to pursue additional restructuring initiatives to preserve value and optionality, including possible out of court restructurings, or in-court relief, which could have a material and adverse impact on stockholders. The amendment also, among other things and subject to certain exceptions described therein, removes certain flexibility the Company had to pay dividends and other distributions, incur indebtedness for borrowed money, consummate asset sales, make intercompany transfer of assets and make investments. The Company is required to comply with the below covenants under the Revolving Credit Agreement: •Beginning with the fiscal quarter ended March 31, 2025, for quarters in which the Revolving Facility is greater than 50% drawn, the Consolidated First Lien Debt Ratio must be below the following: (i) 6.50 to 1.00, for the fiscal quarter ended December 31, 2025, (ii) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 through September 30, 2026, and (iii) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter 89 Table of Contents thereafter. The Consolidated First Lien Debt Ratio test was not tested for the Test Periods ending June 30, 2025 and September 30, 2025. •Beginning with fiscal quarter ended March 31, 2025, the Fixed Charge Coverage Ratio must be less than or equal to (i) 1.00 to 1.00, for the fiscal quarter ended December 31, 2025 and each fiscal quarter thereafter. The Fixed Charge Coverage Ratio test was not tested for the Test Periods ended June 30, 2025 and September 30, 2025. •The Company is also required to maintain a minimum consolidated liquidity of (i) $50.0 million as of the last day of each month and (ii) $100.0 million as of the last day of any fiscal quarter (other than for the fiscal quarter ended December 31, 2025, which shall not be tested). The Company was not in compliance with the Consolidated First Lien Debt Ratio and the Fixed Charge Coverage Ratio as of December 31, 2025. Such defaults are subject to forbearance under the RSA pursuant to which the lenders have agreed subject to certain conditions, to refrain from exercising remedies with respect to specified defaults until termination of the RSA or the closing of the Restructuring Transaction. If the Restructuring Transaction is not consummated or the RSA is terminated, the lenders thereunder could accelerate the outstanding indebtedness. Upon completion of the Restructuring Transaction contemplated under the RSA, the Revolving Facility will no longer be outstanding. Letter of Credit Facility In July 2021, we entered into an uncommitted letter of credit and reimbursement agreement (the “Letter of Credit Agreement”) with a bank for the issuance of letters of credit for an aggregate amount of up to $75.0 million (the “Letter of Credit Facility”). Through December 31, 2023, the Letter of Credit Facility was amended multiple times to increase the availability to $350.0 million. In 2025, the Letter of Credit Facility was amended multiple times to reduce the availability to $195.0 million. As of December 31, 2025, the Company had $195.0 million of letters of credit outstanding under the Letter of Credit Facility. The obligations under the Letter of Credit Facility are guaranteed by certain of our subsidiaries, including those that own our FLNG 1 Project and FLNG 2. The Letter of Credit Facility is secured by substantially the same collateral as the first lien obligations under the Revolving Facility and Term Loan B Credit Agreement. In November 2025, we entered into the eleventh amendment to the Letter of Credit Agreement to, among other things, (a) extend the maturity date of the Letter of Credit Facility to March 31, 2026, (b) provide for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio covenants contained therein for the fiscal quarters ended December 31, 2025, (c) remove the minimum liquidity requirement contained therein with respect to each fiscal quarter, (d) remove certain flexibility we had to pay dividends and other distributions, and (e) restrict our ability to make payments of principal or interest accruing on certain outstanding indebtedness. As of December 31, 2025, the Company had $195.0 million of letters of credit outstanding under the Letter of Credit Facility. Term Loan B Credit Agreement On August 3, 2023, we entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) in an aggregate principal amount of $400.0 million. The Bridge Term Loans were initially set to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%. On October 30, 2023, we entered into a credit agreement (the “Term Loan B Credit Agreement”) pursuant to which the lenders funded term loans in an aggregate principal amount of $856.0 million (“Term Loan B”). Borrowings were issued at a discount, and we received proceeds of $787.5 million. The proceeds from the Term Loan B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature on the earliest of (i) October 30, 2028 if the 2026 Notes are refinanced in full prior to their maturity and (ii) July 31, 2026, if any of the 2026 Notes remain outstanding as of such date. Quarterly principal payments of approximately $2.1 million are required beginning March 2024. The obligations under the Term Loan B are guaranteed by certain of our subsidiaries, including those that own our FLNG 1 Project and FLNG 2. The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2026 Notes, the Revolving Facility, and, in addition, is secured by assets compromising our FLNG 1 Project. 90 Table of Contents The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Credit Agreement) plus 5.0%. We may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. We are required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ended December 31, 2024, we will be required to prepay the Term Loan B with our Excess Cash Flow (as defined in the Term Loan B Credit Agreement). In March 2025, we entered into an amendment to the Term Loan B Credit Agreement. Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425.0 million, which increased the total outstanding principal amount to $1,272.4 million (“Term Loan B”). The incremental term loans were issued at a discount, and we received proceeds, net of discount, of $391.0 million. The incremental term loans are subject to the same maturity date as the term loans under the original agreement. Quarterly principal payments of approximately $3.2 million were required beginning June 2025. The obligations under the Term Loan B are guaranteed by certain of our subsidiaries, including those that own our FLNG 1 Project and FLNG 2. The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2026 Notes, the Revolving Facility, and, in addition, is secured by assets compromising the FLNG 1 Project. The Term Loan B Credit Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B. The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the amendment) plus 5.5%. The Company may prepay the Term Loan B at its option subject to prepayment premiums until March 10, 2028 and customary break funding costs. The Company is required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances and with the Company’s Excess Cash Flow (as defined in the amendment), in each case subject to certain exceptions and thresholds. The Company must comply with the same covenant requirements as those under the original agreement. The Term Loan B contains cross acceleration provisions that would allow these lenders to accelerate the maturity date of outstanding principal under the Term Loan B upon an acceleration of outstanding principal balances under other credit agreements and indentures, including the New 2029 Notes Indenture, Revolving Credit Agreement and Term Loan A Credit Agreement. Uncured events of default exist under the Term Loan B Credit Agreement, as well as these other indentures and credit agreements, and as such, the outstanding principal balance of the Term Loan B has been presented as a current liability. Upon completion of the Restructuring Transaction contemplated under the RSA, the Term Loan B will no longer be outstanding. Term Loan A Credit Agreement In July 2024, we entered into a credit agreement (“Term Loan A Credit Agreement”) for a senior secured, multiple draw term loan facility in an aggregate principal amount of up to $700.0 million (“Term Loan A”). During 2024, we drew $350.0 million on the Term Loan A. In March 2025, the Company entered into an amendment to the Term Loan A Credit Agreement. Pursuant to the amendment, the future borrowing commitments are reduced to zero, eliminating the potential for future borrowings under the Term Loan A Credit Agreement. In May 2025, the Company entered into an additional amendment to the Term Loan A Credit Agreement, which, among other things, (i) requires $55.0 million of proceeds from the sale of the Jamaica Business to be used to prepay a portion of loans currently outstanding; (ii) increases the applicable margin to 6.70% for SOFR loans and 5.70% for Base Rate Loans and implement a Term SOFR floor of 4.30% for the initial term loans and a base rate minimum of 5.30%; (iii) requires the Company to make mandatory prepayments with 12.5% of proceeds of a request for equitable adjustment and any other proceeds related to the early termination of contracts associated with the grid stabilization project in Puerto Rico, if and when such proceeds are received. Additionally, this amendment amends certain of the financial covenants, whereby the consolidated first lien debt ratio cannot exceed (i) 6.50 to 1.00, for the fiscal quarter ended December 31, 2025, (ii) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 and September 30, 2026 and (iii) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter. The amendment added a fixed charge coverage ratio covenant and removed the debt to total capitalization covenant. The Company cannot permit 91 Table of Contents the fixed charge coverage ratio for the Company and its restricted subsidiaries to be less than or equal to 1.00 to 1.00 for the fiscal quarter ended September 30, 2025 and each fiscal quarter thereafter. The obligations under the Term Loan A Credit Agreement are guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes, 2029 Notes, our Revolving Facility, our letter of credit facility (the “Letter of Credit Facility”) and our Term Loan B, other than the guarantors comprising the FLNG 1 Project (who guarantee the Revolving Facility, the Letter of Credit Facility, and the Term Loan B). The obligations under the Term Loan A Credit Agreement are secured by substantially the same collateral as the collateral securing such facilities, with the exception of the collateral comprising the FLNG 1 Project (which secures the Revolving Facility, the Letter of Credit Facility, and the Term Loan B). Additionally, the Term Loan A is guaranteed by the entities, and secured by the assets, comprising FLNG 2. An equal priority intercreditor agreement governs the treatment of the collateral. The Term Loan A will mature in July 2027 and is payable in full on the maturity date. In the event that our existing 2026 Notes are not refinanced or repaid at least 60 days prior to maturity, amounts outstanding under the Term Loan A will become due and payable on such date. We may prepay the Term Loan A at its option without premium or penalty at any time subject to customary break funding costs. We are required to prepay the Term Loan A with the net proceeds of certain asset sales, condemnations, debt and convertible securities issuances, and extraordinary receipts related to FLNG 2. Additionally, commencing with the first fiscal quarter after the Completion Date, we will be required to prepay the Term Loan A with FLNG 2’s Excess Cash Flow (as defined in the Term Loan A Credit Agreement). The Term Loan A Credit Agreement contains usual and customary representations, warranties and affirmative and negative covenants for financings of this type, including certain representations and warranties related to FLNG 2. The Term Loan A Credit Agreement includes certain other covenants related solely to FLNG 2, including limitations on capital expenditures, restrictions on additional accounts, and restrictions on amendments or termination of certain material documents related to FLNG 2. The Term Loan A contains cross acceleration provisions that would allow these lenders to accelerate the maturity date of outstanding principal under the Term Loan A upon an acceleration of outstanding principal balances under other credit agreements and indentures, including the New 2029 Notes Indenture, Revolving Credit Agreement and Term Loan B Credit Agreement. Uncured events of default exist under the Term Loan A Credit Agreement, as well as these other indentures and credit agreements, and as such, the outstanding principal balance of the Term Loan A has been presented as a current liability. Upon completion of the Restructuring Transaction contemplated under the RSA, the Term Loan A will no longer be outstanding. Short-term Borrowings We may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and concurrently enter into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2025, we had $73.2 million due under these arrangements. During 2025, the we executed multiple amendments to this financing arrangement primarily to extend payment terms. Each of these amendments was accounted for as a debt modification. We did not incur material costs and fees associated with the modifications. Vessel Financing Obligation In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to us at the time of closing were classified as finance leases. Additionally, our charter of certain other vessels will commence only upon the expiration of the vessel’s existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, we accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation for consideration received. We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we recognize revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation; at inception of the arrangement, the effective interest rate on this financing obligation was approximately 18.10% and includes the cash flows that Energos receives from these third-party charters. Charter payments due in 2025 include $57.8 92 Table of Contents million that will be treated as a payment of principal, and this amount is included within the current portion of long-term debt. In November 2025, the Company 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. This transaction resulted in the sale of these vessels that were previously accounted for as a failed sale leaseback. Upon closing of the transaction, the Company derecognized these vessels from Property, plant and equipment with a carrying value of $667.0 million, and derecognized debt of $734.2 million. Tugboat Financing In December 2023, we sold and leased back four tugboat vessels for 15 years receiving proceeds of $46.7 million. (“Tugboat Financing”). The leasebacks of the tugboat vessels were classified as finance leases, and as such, we accounted for the Tugboat Financing as a failed sale-leaseback and has recorded a financing obligation for consideration received. The effective interest rate on this financing obligation is approximately 16.92%. Brazil Financing Notes In February 2025, one of our consolidated subsidiaries entered into an agreement to issue up to $350.0 million aggregate principal amount of 15.0% Senior Secured Notes due 2029 (the “Brazil Financing Notes”) at a purchase price of 97.75% of par. The Brazil Financing Notes mature on August 30, 2029; the principal is due in full on the maturity date. Interest is payable quarterly in arrears beginning on June 30, 2025, and for the first 30 months that the Brazil Financing Notes are outstanding, interest due can be paid in kind and added to the principal amount. A portion of the proceeds from the issuance of the Brazil Financing Notes of $208.7 million was used to repay the Barcarena Debentures in full. The Brazil Financing Notes contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Brazil Financing Notes. The repayment of the Barcarena Debentures was evaluated on a creditor-by-creditor basis to determine whether the transaction should be accounted for as a modification or extinguishment of debt. As a result of this evaluation, a portion of the repayment was determined to be an extinguishment of debt and, therefore, the Company recorded a debt extinguishment loss of $0.4 million to write off a pro-rata amount of unamortized issuance costs. The outstanding principal balance of Brazil Financing Notes has been presented as a current liability as the Company provides a parent company guarantee under the agreement and uncured events of default exist under certain indentures and credit agreements. Upon completion of the Restructuring Transaction contemplated under the RSA, NFE will no longer own BrazilCo, including the Brazil Financing Notes. PortoCem Debentures PortoCem Debentures included a non-automatic early maturity provision whereby upon multiple downgrades of the Company’s credit rating, early maturity may be declared if approved by the majority of debenture holders. Our credit ratings were downgraded during 2025, the debenture holders have unanimously permanently waived their ability to declare an early maturity event due to these credit rating downgrades in exchange for two additional bank guarantees, totaling $129.1 million. During 2025, the Company provided the first required $50.0 million bank guarantee, which may be drawn by the debenture holders if there is a breach under the Equity Contribution Agreement; an additional bank guarantee of $79.1 million is required to be provided by May 10, 2026, subject to a 45 day cure period. Based on the Company’s current liquidity, the Company determined that it is not currently probable that the bank guarantee can be provided absent an agreement with its existing creditors or new lenders, and as such the PortoCem Debentures have been classified as a current liability. If the Company fails to provide the bank guarantee of $79.1 million, an automatic early maturity event will occur, and substantially all of the Company’s outstanding indebtedness would be payable on demand. In addition, certain of the creditors that have executed the RSA would have the right to terminate the RSA if the debenture holders declare an automatic early maturity. Upon completion of the Restructuring Transaction contemplated under the RSA, NFE will no longer own BrazilCo, or be subject to the PortoCem Debentures. 93 Table of Contents South Power 2029 Bonds On May 14, 2025, we completed the sale of the Jamaica Business. In conjunction with closing, we repurchased all outstanding South Power Bonds for $227.2 million, including a 1.0% prepayment penalty and accrued interest. Turbine Financing In May 2024, we executed a loan agreement with a lender to borrow $148.5 million under a promissory note secured by certain turbines owned by a wholly-owned subsidiary of ours (the “Turbine Financing”). The Turbine Financing bears interest at 10.30%, and the principal is partially repayable in monthly installments over the 36-month term of the loan with the balance due upon maturity in June 2027. The Turbine Financing contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Turbine Financing does not contain any restrictive financial covenants. We were required to pay a deposit of approximately $6.0 million that will be held by the lender throughout the term of the borrowing recorded in Other non-current assets, net. EB-5 Loan Agreement On July 21, 2023, we entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100.0 million, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE’s green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. As of December 31, 2025, the availability under the EB-5 Loan Agreement has been fully funded, and there is an aggregate principal amount of $100.0 million outstanding. The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants. Summary of Critical Accounting Estimates The preparation of consolidated financial statements in conformity with GAAP requires us to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. We evaluate our estimates and related assumptions regularly, and we believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates. Impairment of long-lived assets We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, an impairment of goodwill, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment. When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. The undiscounted cash flows consist of cash flows from current contracts, future projected contracts, estimated capital expenditures, and estimated residual or scrap values. The recoverability assessment also considers the probability of development, which may be impacted by the viability of the projects and our liquidity position. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. 94 Table of Contents Recent Accounting Standards For descriptions of recently issued accounting standards, refer to Note 5 of our notes to consolidated financial statements included in this Annual Report.