New Fortress Energy Inc. 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and under similar headings in the Annual Report on Form 10-K for the year ended December 31, 2023 (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 indicates otherwise, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries. Overview We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in our Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Very-Low Carbon Future.” Our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships. Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third-party suppliers and from our own liquefaction facility in Miami, Florida. We expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." Our first FLNG facility began producing LNG in July 2024. The first full cargo was loaded onto the Energos Princess vessel and set sail for Europe on September 30, 2024. Following the anticipated sale of our Miami Facility, we expect to continue sourcing LNG from third parties and for a portion of our supply to be generated by our first FLNG unit. The Terminals and Infrastructure segment includes all terminal operations in Jamaica, 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 or logistics operations, which allows us to optimally manage our LNG supply and fleet. Our Ships segment includes all vessels which are leased to customers under long-term arrangements. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire. Our Current Operations – Terminals and Infrastructure Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica 39 Table of Contents Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, 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. Montego Bay Facility The Montego Bay Facility serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue power plant in Montego Bay, Jamaica ("Bogue Power Plant"). Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 60,000 MMBtu of LNG per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users. Old Harbour Facility The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay agreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers. 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, industrial end-user customers in Puerto Rico, and after being awarded a new gas sale agreement in the first quarter of 2024, PREPA's gas-fired power plants throughout the island of Puerto Rico. In the first and second quarters of 2023, we entered into agreements for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas. Our customer was contracted by the U.S. Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 150MW of duel-fuel power generation using our gas supply in the second quarter of 2023, and the remaining 200MW was commissioned in September 2023. In March 2024, o ur contract to provide emergency power services to support the grid stabilization project was terminated. We are pursuing a $659 million request for equitable adjustment related to the early termination of our contract. The actual amount of any such adjustment and the timing of any related payments may be materially different than management’s current estimate. As a result, the Company cannot offer any assurance as to the actual amount that may be recovered pursuant to such request or subsequent claim, if any. As the outcome of this process is uncertain, we have not recognized any revenue associated with the close out of our contract. In March 2024, we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA under an Asset Purchase Agreement ("APA"). The purchase price was $306.6 million, and the APA includes an option for PREPA to purchase three additional turbines for additional purchase price of $65.7 million. We recognized a loss of $77.5 million in Loss on sale of assets, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). In the first quarter of 2024, we were also awarded a new gas sale agreement with PREPA to supply up to 80 TBtu annually to PREPA's gas-fired power plants, including to the turbines that were sold pursuant to the APA. The contract initially has a one year term that is renewable annually for three additional annual periods. In the first quarter of 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 40 Table of Contents improving reliability of power generation in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees. The service period under the contract commenced on July 1, 2023. La Paz Facility In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power. We placed the La Paz Power Plant into service in the third quarter of 2023. In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. In the third quarter of 2024, we executed a 10-year gas sales agreement to supply natural gas to additional CFE facilities on take-or-pay basis. Miami Facility Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers. On June 30, 2024, the Company entered into a definitive agreement to sell its Miami Facility for $62 million. The transaction is expected to close in the fourth quarter of 2024 subject to customary terms and conditions. Our LNG Supply and Cargo Sales NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts expected to commence in 2027; and 3) supply from our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, which are expected to commence in 2027. Finally, we plan to source production from our own Fast LNG facilities, the first of which began to produce LNG in July 2024 . We sold the first full cargo from this facility on September 30, 2024. We plan to expand that capacity when additional Fast LNG units come online. Natural gas and LNG markets have experienced unprecedented price volatility in recent years. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is largely based on the Henry Hub index price plus a fixed fee component. Additionally, with our own Fast LNG production, we plan to further mitigate our exposure to variability in LNG prices. In 2022 and 2023, our revenue and results of operations benefited from selling cargos into the global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals. Our Current Operations – Ships Our Ships segment includes Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are leased to customers under long-term arrangements. At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and described in more detail below, we plan to charter these vessels for our own operational purposes. The results of operations of vessels utilized in our terminal operations are reflected in the 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 41 Table of Contents Sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos. Our Development Projects Our projects currently under development include our development of a series of modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world through our Fast LNG technologies; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plants (“Barcarena Power Plant” and "PortoCem Power Plant") located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); our LNG terminal (“Ireland Facility”) and power plant in Ireland, our first green hydrogen project ("ZeroPark I") and Klondike Digital Infrastructure, our newly-launched power and data center infrastructure business ("Klondike"). We are also in active discussions to develop projects in multiple regions around the world that may have significant demand for additional power, LNG and natural gas, although there can be no assurance that these discussions will result in additional contracts or that we will be able to achieve our target revenue or results of operations. The design, development, construction and operation of our projects are highly regulated activities and subject to various approvals and permits. The process to obtain required permits, approvals and authorizations is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects. We describe each of our current development projects below. Fast LNG We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. Our “Fast LNG,” or “FLNG,” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a lower cost and faster deployment schedule than other greenfield alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application. Our initial Fast LNG units were constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of liquefaction projects. In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. Our first Fast LNG unit has been deployed offshore to Altamira, Mexico, and we expect to deploy additional units over the next two years. We describe our currently planned projects below. Altamira In the first quarter of 2023, we executed an agreement with CFE to supply natural gas for one FLNG unit located off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million ton per annum (“MTPA”) FLNG unit is utilizing CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in the process of commissioning the project. While we experienced delays in commissioning our first FLNG unit, which impacted our results of operations in this period and may impact our results in future periods, in July 2024, we began to produce LNG, and we expect to achieve run-rate production later in 2024. We sold the first full cargo from this facility on September 30, 2024. In the first quarter of 2024, we executed an agreement with CFE to supply natural gas to an onshore liquefied natural gas terminal with up to two 1.4 MTPA FLNG units. The terminal is to be located at the existing Altamira LNG import facility and would source feedgas from the Sur de Texas-Tuxpan Pipeline. The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals. Existing 42 Table of Contents infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks. Louisiana In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG. Lakach We have been in discussions with Petróleos Mexicanos (“Pemex”) to form a long-term strategic partnership to develop the Lakach deepwater natural gas field for Pemex to supply natural gas to Mexico's onshore domestic market and for NFE to produce LNG for export to global markets. Our initial agreements were terminated in the fourth quarter of 2023, however, NFE continues to be in active discussions with Pemex to develop or monetize an offshore project. Puerto Sandino Facility We are developing a liquefied natural gas receiving, transloading and regasification facility in Puerto Sandino, Nicaragua, as well as a pipeline connecting the facility with our Puerto Sandino Power Plant. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,000 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term strategy, we are evaluating solutions to optimize power generation and delivery to other markets, connected to our power plant through a regional transmission line starting in 2025. 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 processing over one million 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 substantially completed our Barcarena Facility in 2022 and are in process of final commissioning. The Barcarena Facility will also supply our new 630MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”). The power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid. We expect to complete the Barcarena Power Plant and begin delivering power to nine committed offtakers for 25 years beginning in 2025. In March 2024, we closed the acquisition of PortoCem Geração de Energia S.A. ("PortoCem"), a wholly-owned subsidiary of Ceiba Fundo de Investimento em Participações Multiestratégia- Investimento no Exterior ("Ceiba Energy") in exchange for newly issued 4.8% NFE redeemable Series A Convertible Preferred Stock. PortoCem is the owner of a 15-year 1.6GW capacity reserve contract in Brazil. We have received approval to transfer the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE will build the PortoCem Power Plant to supply the capacity reserve contract using gas from the Barcarena Facility. We expect to begin delivering electricity under the acquired capacity reserve contract in July 2026. Santa Catarina Facility The Santa Catarina Facility is located on the southern coast of Brazil and consists of an FSRU with a processing capacity of approximately 500,000 MMBtu from LNG per day and LNG storage capacity of up to 138,000 cubic meters. We have developed 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. We are in the process of final commissioning of our Santa Catarina Facility. Ireland Facility 43 Table of Contents We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála, 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 the ABP did not have appropriate grounds for the denial of our permit. The ABP has been directed to reconsider our permit application in accordance with Irish law. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations. ZeroParks In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies. Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the western hemisphere and numerous petrochemical manufacturers, many of which require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect ZeroPark I to be the largest green hydrogen plant in the United States. Klondike We recently launched Klondike, a power and data center development business dedicated to working with hyperscale customers to build and operate data centers. This venture comes in response to a significant need for turnkey digital infrastructure to support the next stage of explosive growth in artificial intelligence. Klondike will employ independent power sources that utilize behind-the-meter on-site power. This innovative approach is designed to address all major constraints of digital infrastructure development, providing grid stability, significant transmission capacity, power reliability, energy cost savings, and scalability. This approach not only reduces the demand for power from the grid but also contributes power back to it. Klondike is currently developing a geographically diverse portfolio of data center sites to satisfy the requirements of hyperscale users. Klondike has more than 1,000 acres of developable land across sites in Brazil, Ireland, and the United States that it either owns or leases. These locations have large existing power plants or permits in process to build several gigawatts of power, connectivity to fiber networks, access to transmission and water. Recent Developments Equity Offering On October 1, 2024, the Company entered into an Underwriting Agreement with several underwriters to issue and sell 46,349,942 shares of our Class A common stock, par value $0.01 per share, at a purchase price to the public of $8.63 per share, less underwriting discounts and commissions, in a registered public offering (the "Equity Offering"). Our chief executive officer, Wesley R. Edens, agreed to purchase 5,793,742 shares at the public offering price per share and on the same terms as the other purchasers in the Equity Offering. The Equity Offering closed on October 2, 2024. We received net proceeds of approximately $387.3 million after underwriters' discounts and commissions and the estimated offering expenses payable by the Company. 44 Table of Contents Transaction Support Agreement and Exchange and Subscription Agreement On September 30, 2024, we entered into a Transaction Support Agreement (the "TSA") with certain holders of our 2025 Notes, 2026 Notes, and 2029 Notes. The TSA relates to a series of transactions, among the Company, certain of the Company's direct and indirect subsidiaries and certain holders of the 2025 Notes, 2026 Notes and 2029 Notes ( the "Supporting Holders"), intended to extend the maturity profile of our indebtedness while providing additional operating liquidity and financial flexibility. On November 6, 2024, we entered into a privately negotiated exchange and subscription agreement (the "Exchange and Subscription Agreement") with the Supporting Holders to implement the transactions described in the TSA. Pursuant to the Exchange and Subscription Agreement, (i) NFE Financing LLC ("NFE Financing"), an indirectly owned subsidiary of the Company, will sell to the Supporting Holders approximately $1.2 billion aggregate principal amount of 12.00% Senior Secured Notes due 2029 (the "New Notes") (the transactions described in clause (i), the "Subscription Transactions") and (ii) NFE Financing will issue to the Supporting Holders $1.5 billion aggregate principal amount of New Notes in a dollar-for-dollar exchange for our 2026 Notes and 2029 Notes (the "Exchange Transactions" and together with the Subscription Transactions, the "Transactions"). The New Notes will be issued pursuant to an indenture (the "New Notes Indenture") and will be issued in private placements in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act. We intend to use net proceeds from the Transactions to repay in full the outstanding aggregate principal amount of our 2025 Notes and for general corporate purposes. Pursuant to the Exchange and Subscription Agreement, the Supporting Holders may elect to receive a commitment fee equal to either (i) 5% of the aggregate principal amount of such Supporting Holder’s New Notes, payable in shares of our Class A common stock, 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 Notes, payable in kind in the form of additional New Notes (the "Commitment Fee Notes"), or (iii) a combination of the foregoing. To the extent any Supporting Holder elects to receive Commitment Fee Notes, the equivalent value in Commitment Fee Shares will be ratably reallocated amongst the other Supporting Holders to ensure that the Supporting Holders will in any case receive 5% of the total amount of New Notes payable in Commitment Fee Shares. In the event any Supporting Holder elects to receive the Commitment Fee Shares, such Supporting Holder will enter into a Registration Rights Agreement with the Company, pursuant to which such Supporting Holder is entitled to certain registration rights and subject to certain lock-up restrictions. Any Supporting Holders may not, subject to customary exceptions, offer, sell, contract to sell, pledge or otherwise dispose of the Commitment Fee Shares for a period of six months from the date of the Registration Rights Agreement without our prior written consent. New Notes Indenture Interest on the New Notes will be payable semi-annually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025. The New Notes will mature on November 15, 2029 and are payable in full on maturity date. NFE Financing may redeem the New Notes, in whole or in part, at any time prior to maturity, subject to certain prepayment premiums. NFE Financing is required to prepay the New Notes, subject to repurchase premiums, upon occurrence of change of control events and other specified prepayment events. Additionally, the New Notes will be subject to a par repurchase offer in connection with any “Pass Through Prepayment Event” (defined as any prepayment made under the Brazil Parent Credit Agreement or the Series II Credit Agreement (each, as defined below)). The New Notes will be guaranteed on a senior secured basis by NFE Financing’s wholly-owned subsidiary, Bradford County Real Estate Partners LLC ("New Notes Guarantor"), which owns our land in Wyalusing, Pennsylvania. The New Notes will be secured by first-priority liens on (a) all assets of NFE Financing, including the promissory note evidencing indebtedness under the Series II Credit Agreement, the promissory note evidencing indebtedness under the Brazil Parent Credit Agreement, approximately 45% of the equity in NFE Brazil Holdings Limited ("NFE Brazil Holdings"), which owns our Brazil business, and 100% of the equity in the New Notes Guarantor and (b) all assets of the New Notes Guarantor. In connection with NFE Financing’s issuance of the New Notes, NFE will: (i) enter into approximately $1.4 billion Series II Credit Agreement (as defined below) with NFE Financing, (ii) enter into an approximately $970 million Series I Credit Agreement (as defined below) with NFE Brazil Investments LLC (“Brazil Parent”), an indirectly owned, restricted subsidiary of the Company and the direct parent of NFE Financing, and (iii) further cause Brazil Parent to enter into an approximately $970 million Brazil Parent Credit Agreement (as defined below) with NFE Financing. Intercompany loans 45 Table of Contents Brazil Parent Credit Agreement NFE Financing and Brazil Parent will enter into a credit agreement (the “Brazil Parent Credit Agreement”), whereby NFE Financing will provide a term loan of approximately $970 million (the “Brazil Parent Term Loan”) to Brazil Parent, which will mature in November 2029. The obligations under the Brazil Parent Credit Agreement will be secured by substantially all assets of Brazil Parent (including a pledge of the equity interests held by Brazil Parent in NFE Brazil Holdings). Brazil Parent may redeem the Brazil Parent Term Loan, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. Brazil Parent is required to prepay the Brazil Parent Term Loan, subject to repurchase premiums, upon occurrence of certain events, including any change of control and receipt of net proceeds from any prepayment under the Series I Credit Agreement (as defined below). The Brazil Parent Credit Agreement is expected to contain usual and customary representations and warranties, covenants and events of default for financings of this type. Series I Credit Agreement NFE and Brazil Parent will enter into a term loan credit agreement (“Series I Credit Agreement”), under which Brazil Parent will provide NFE a senior secured term loan in an aggregate principal amount of approximately $970 million (the “Series I Term Loan”). We intend to use proceeds to repay in full the outstanding aggregate principal amount of our 2025 Notes and consummate a portion of the Exchange Transactions. Series II Credit Agreement NFE and NFE Financing will enter into a term loan credit agreement (“Series II Credit Agreement”), under which NFE Financing will provide NFE a senior secured term loan in an aggregate principal amount of approximately $1.4 billion (the “Series II Term Loan”). The proceeds will be used to consummate the Exchange Transactions. Both Series I and Series II Term Loan will mature in November 2029 and will be payable in full on the maturity date. The obligations under both the Series I Credit Agreement and Series II Credit Agreement will be guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes and the 2029 Notes. The obligations under the Series I and Series II Credit Agreement will be secured by substantially the same collateral that currently secures the 2026 Notes and 2029 Notes. An equal priority intercreditor agreement will govern the treatment of the collateral. We may redeem the Series I and Series II Term Loan, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. In addition, we will be required to prepay the Series I and Series II Term Loan upon the occurrence of any change of control (as defined in the New Notes Indenture and the Brazil Parent Credit Agreement), and with the net proceeds of certain asset sales, condemnations and debt and convertible securities issuances. Both Series I and Series II Credit Agreement are expected to contain customary representations, warranties, covenants and events of default, subject to certain thresholds and grace periods, typical for financings of this type. Credit Agreement Amendments On November 6, 2024, we entered into the Ninth Amendment to our Revolving Credit Agreement (the “Ninth Amendment”), which extends the maturity date of the Revolving Facility for consenting lenders from April 15, 2026 to October 15, 2027, subject to certain events that would cause the maturity to spring to an earlier date as described in the Ninth Amendment. On November 6, 2024, we entered into the Fifth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement (the “Fifth Amendment”, and together with the “Ninth Amendment,” the “Amendments”). The Amendments, among other things, modify the definition of Excluded Assets and exclude certain assets of our Brazil business from the definition of Excluded Assets. The Amended Credit Agreements also amend the financial covenant that tests the consolidated first lien debt ratio. The consolidated first lien debt ratio cannot exceed (i) 9.50 to 1.00, for the fiscal quarters ending March 31, 2025 through June 30, 2025, (ii) 8.50 to 1.00, for the fiscal quarters ending September 30, 2025 through December 31, 2025, (iii) 8.00 to 1.00, for the fiscal quarters ending March 31, 2026 through June 30, 2026, and (iv) 7.50 to 46 Table of Contents 1.00, for the fiscal quarters ending September 30, 2026 and each fiscal quarter thereafter. The Amended Credit Agreements also add a fixed charge coverage ratio test. Commencing with the fiscal quarter ending March 31, 2025, we cannot permit the fixed charge coverage ratio (the ratio of consolidated EBITDA to fixed charges) for the Company and its restricted subsidiaries to be less than 0.80 to 1.00 for the fiscal quarter ending March 31, 2025 and, for the fiscal quarter ending June 30, 2025 and each fiscal quarter thereafter, 1.00 to 1.00. Additionally, the Amendments modify how consolidated EBITDA is calculated to more closely align with the calculations in certain of our existing term loan facilities and also remove the Debt to Total Capitalization Ratio. Lumina Note Purchase Agreement On November 6, 2024, NFE Brazil Financing Limited (“NFE Brazil”), a wholly-owned, indirect subsidiary of the Company, entered into a note purchase agreement (the “Note Purchase Agreement”) to issue and sell up to $350 million aggregate principal amount of its 15% Senior Secured Notes due 2029 (the “NFE Brazil Notes”) at a purchase price of 97.75% of the principal amount. The obligations under the NFE Brazil Notes will be guaranteed by the Company and certain subsidiaries of NFE Brazil, and NFE Brazil, its subsidiary guarantors and certain of its other subsidiaries will grant security interests in certain of their assets to secure the NFE Brazil Notes. Other Matters On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending. On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue. On September 26, 2024, the United States Coast Guard ("USCG") filed a Letter of Recommendation with FERC in which it assessed our Letter of Intent dated April 12, 2024, and our Waterway Suitability Assessment, dated August 26, 2024, in respect of future ship to ship transfers with alternative vessels, and recommended against the allowance of the proposed operations. Further, 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 and are awaiting a response. 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 scheduled for November 18, 2024 in accordance with the National Environmental Policy Act. Results of Operations – Three Months Ended September 30, 2024 compared to Three Months Ended June 30, 2024 and Nine Months Ended September 30, 2024 compared to Nine Months Ended September 30, 2023 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 47 Table of Contents 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 September 30, 2024 and June 30, 2024, and for the nine months ended September 30, 2024 and September 30, 2023: Three Months Ended September 30, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 482,200 $ 43,062 $ 525,262 $ 42,273 $ 567,535 Cost of sales (1)(2) 325,292 — 325,292 — 325,292 Vessel operating expenses (4) — 8,254 8,254 — 8,254 Operations and maintenance (4) 32,062 — 32,062 — 32,062 Deferred earnings from contracted sales (5) 60,000 — 60,000 (60,000) — Segment Operating Margin $ 184,846 $ 34,808 $ 219,654 $ (17,727) $ 201,927 Three Months Ended September 30, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 166,563 Depreciation and amortization 35,364 Consolidated Segment Operating Margin (Non-GAAP) $ 201,927 Three Months Ended June 30, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 385,428 $ 42,578 $ 428,006 $ — $ 428,006 Cost of sales (1)(2) 221,860 — 221,860 — 221,860 Vessel operating expenses (4) — 8,503 8,503 — 8,503 Operations and maintenance (4) 39,292 — 39,292 — 39,292 Deferred earnings from contracted sales (5) 90,000 $ — 90,000 (90,000) — Segment Operating Margin $ 214,276 $ 34,075 $ 248,351 $ (90,000) $ 158,351 48 Table of Contents Three Months Ended June 30, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 120,938 Depreciation and amortization 37,413 Consolidated Segment Operating Margin (Non-GAAP) $ 158,351 Nine Months Ended September 30, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 1,515,365 $ 128,224 $ 1,643,589 $ 42,273 $ 1,685,862 Cost of sales 776,269 — 776,269 — 776,269 Vessel operating expenses — 25,153 25,153 — 25,153 Operations and maintenance 139,902 — 139,902 — 139,902 Deferred earnings from contracted sales(5) 150,000 — 150,000 (150,000) — Segment Operating Margin $ 749,194 $ 103,071 $ 852,265 $ (107,727) $ 744,538 Nine Months Ended September 30, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 621,270 Depreciation and amortization 123,268 Consolidated Segment Operating Margin (Non-GAAP) $ 744,538 Nine Months Ended September 30, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 1,446,017 $ 230,315 $ 1,676,332 $ (21,394) $ 1,654,938 Cost of sales 488,512 — 488,512 114,114 602,626 Vessel operating expenses — 42,295 42,295 (5,948) 36,347 Operations and maintenance 121,187 — 121,187 — 121,187 Segment Operating Margin $ 836,318 $ 188,020 $ 1,024,338 $ (129,560) $ 894,778 Nine Months Ended September 30, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 769,618 Depreciation and amortization 125,160 Consolidated Segment Operating Margin (Non-GAAP) $ 894,778 (1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are economic hedges of our commodity purchases and sales, and realized losses of $0.3 million and realized gains of $141.6 million for the three and nine months ended September 30, 2023, respectively, were recognized as a reduction to Cost of sales in the segment measure. No such transactions were completed in 2024. 49 Table of Contents We recognized unrealized gains of $0.4 million and unrealized losses of $107.9 million on the mark-to-market value of derivative transactions for the three and nine months ended September 30, 2023, respectively, and these gains and losses reconcile Cost of sales in the segment measure to Cost of sales in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) . We have excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6.2 million for the nine months ended September 30, 2023 are shown as a reduction to Cost of sales in the segment measure. There were no contract acquisition costs incurred in 2024. (2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). (3) Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $150.0 million; a portion of these deferred earnings of $42.3 million were recognized upon delivery during the third quarter of 2024. In 2023, the effective share of revenues, expenses and operating margin attributable to our ownership of the common units of Hilli LLC in the segment measure, prior to the disposition to this investment, as well as unrealized mark-to-market gain or loss on derivative instruments, are also removed. (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 defined under GAAP. (5) Deferred earnings from contracted sales represent forward sales transactions that were contracted in the current period and prepayment for these sales was received. Revenue will be recognized in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) when delivery under these forward sales transactions is completed from the fourth quarter of 2024 through 2025. Terminals and Infrastructure Segment Three Months Ended, (in thousands of $) September 30, 2024 June 30, 2024 Change Total revenues $ 482,200 $ 385,428 $ 96,772 Cost of sales (exclusive of depreciation and amortization) 325,292 221,860 103,432 Operations and maintenance 32,062 39,292 (7,230) Deferred earnings from contracted sales 60,000 90,000 (30,000) Segment Operating Margin $ 184,846 $ 214,276 $ (29,430) Nine Months Ended, (in thousands of $) September 30, 2024 September 30, 2023 Change Total revenues $ 1,515,365 $ 1,446,017 $ 69,348 Cost of sales (exclusive of depreciation and amortization) 776,269 488,512 287,757 Operations and maintenance 139,902 121,187 18,715 Deferred earnings from contracted sales 150,000 — 150,000 Segment Operating Margin $ 749,194 $ 836,318 $ (87,124) Total revenue Total revenue for the Terminals and Infrastructure Segment increased by $96.8 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The increase was primarily driven by higher cargo sales and Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment, partially offset by lower incentive fee revenue from the Genera's operation and maintenance contract. The increase in revenue in the third quarter of 2024 when compared to the second quarter of 2024 was primarily attributable to the following: 50 Table of Contents • Revenue from cargo sales was $174.6 million for the three months ended September 30, 2024, increasing from $24.5 million for the three months ended June 30, 2024. • Volumes delivered to downstream terminal customers were substantially consistent, increasing from 20.2 TBtu in the second quarter of 2024 to 20.7 TBtu in the third quarter of 2024. • The average Henry Hub index pricing used to invoice our downstream customers increased by 14% for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. Total revenue for the Terminals and Infrastructure Segment increased by $69.3 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023, and the increase in revenue was primarily attributable to the following: • For the nine months ended September 30, 2024, volumes delivered to downstream customers were 62.8 TBtu as compared to 46.1 TBtu for the nine months ended September 30, 2023. • In 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets in the second and third quarters of 2023, and the increase in volumes for the nine months ended September 30, 2024 is primarily attributable to additional sales in Puerto. Our customer terminated the grid stabilization project in the first quarter of 2024, but we continue to sell volumes into these power plants under a new island-wide gas sale agreement signed with PREPA. Although we delivered significantly higher volumes in the current year, our revenue was impacted by lower Henry Hub pricing and lower cargo sale revenue. • The average Henry Hub index pricing used to invoice our downstream customers decreased by 22% for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. • The Company had $199.1 million in cargo sales for the nine months ended September 30, 2024. Revenue from cargos sales was $617.1 million for the nine months ended September 30, 2023. 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. Historically, our LNG and natural gas supply has been purchased from third parties or converted in our Miami Facility. Following the anticipated sale of our Miami Facility, we expect to continue sourcing LNG from third parties and for a portion of our supply to be generated by our first FLNG unit. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our liquefaction facilities are also included in Cost of sales. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide operations and maintenance services to PREPA's thermal generation assets, and cost to provide these services is included in Cost of sales. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue. Cost of sales increased by $103.4 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024, which was attributable to higher cost of gas purchased and cargo sales. Our cost to deliver natural gas volumes increased to $6.65 per MMBtu for the three months ended September 30, 2024 from $6.42 per MMBtu for the three months ended June 30, 2024. After our FLNG asset is fully commissioned and operational, we expect to be able to produce LNG at a lower cost than the LNG purchased under our supply contracts. We incurred increased cost of LNG for LNG cargo sales during the third quarter of 2024 by $76.7 million compared to the second quarter of 2024 due to higher volumes delivered. Cost of sales increased by $287.8 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023, which was attributable to the following activity: • We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $76.4 million during the nine months ended September 30, 2024 due to increased volumes delivered. We delivered 36% more volume to our downstream terminal customers in the current period. While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was lower, 51 Table of Contents decreasing to $ 6.65 per MMBtu for the nine months ended September 30, 2024 from $ 7.26 per MMBtu for the nine months ended September 30, 2023. • Vessel costs increased by $59.8 million, for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase is primarily driven by additional vessels being used for servicing our terminals during 2024. • We recognized payroll and other operating costs of $77.0 million to provide services under Genera's operations and maintenance contract for the nine months ended September 30, 2024 compared to $16.3 million for the nine months ended September 30, 2023; these costs are passed onto PREPA. Only one quarter of such costs were incurred during the nine months ended September 30, 2023 as our contract commenced on July 1, 2023. • We incurred decreased cost of LNG for LNG cargo sales during the nine months ended September 30, 2024 by $72.7 million as our LNG cargo sale activity has been significantly lower in the first three quarters of 2024. • In the nine months ended September 30, 2023, realized gains of $141.9 million from the settlement of commodity swap transactions, entered into as an economic hedge to reduce the market risks associated with commodity prices, were included as reduction of cost of sales in the segment measure. For segment performance measures, unrealized mark to market gains and losses are excluded until settled. No such transactions occurred in the current period. The weighted-average cost of our LNG inventory balance to be used in our operations as of September 30, 2024 and December 31, 2023 was $7.46 per MMBtu and $7.33 per MMBtu, respectively. Operations and maintenance Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance decreased by $7.2 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. The decrease was primarily due to lower maintenance costs at our terminals during the third quarter and termination of the lease of three turbines during the second quarter of 2024. Operations and maintenance increased $18.7 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023 . We incurred additional operations and maintenance costs at our La Paz Power Plant during nine months ended September 30, 2024 as it was placed into service in September 2023. Additional operations and maintenance cost were also incurred at our La Paz Facility in 2024 to meet higher customer demand. Deferred earnings from contracted sales In the second and third quarters of 2024, we completed forward sales receiving prepayments from the buyer of $90.0 million and $60.0 million respectively. The prepayment was based on the fair market value of these sales as compared to our supply cost, and our CODM includes these results in his evaluation of Terminals and Infrastructure operations. Revenue for these sales will be recognized in our Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) as deliveries under this contract will occur in the fourth quarter of 2024 through 2025. A portion of these deferred earnings of $42.3 million were recognized upon delivery during the third quarter of 2024. Both the forward contracted sale and our supply contract are based on Henry Hub which mitigates the impact that changes in commodity pricing will have on our results of operations. Ships Segment Three Months Ended, (in thousands of $) September 30, 2024 June 30, 2024 Change Total revenues $ 43,062 $ 42,578 $ 484 Vessel operating expenses 8,254 8,503 (249) Segment Operating Margin $ 34,808 $ 34,075 $ 733 52 Table of Contents Nine Months Ended, (in thousands of $) September 30, 2024 September 30, 2023 Change Total revenues $ 128,224 $ 230,315 $ (102,091) Vessel operating expenses 25,153 42,295 (17,142) Segment Operating Margin $ 103,071 $ 188,020 $ (84,949) Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of September 30, 2024 , three FSRUs and one LNG carrier were leased to customers under long-term arrangements. On March 15, 2023, we completed disposition of our investment in the common units of Hilli LLC, and after this point, the revenue, expenses and operating margin attributable to our 50% ownership of the Hilli are no longer included in our segment results. In the first quarter of 2024, we sold the vessel Mazo , for a total consideration of $22.4 million resulting in a gain of $0.4 million. The gain on sale is included in Loss on sale of assets, net , in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Total revenue Total revenue for the Ships segment increased by $0.5 million during the three months ended September 30, 2024 compared to the three months ended June 30, 2024 . Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of certain vessels included in the transaction, and as such, we continue to recognize revenue from the charter of these vessels to third parties. Total revenue for the Ships segment decreased $102.1 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. After the disposition of our investment in the common units of Hilli LLC at the end of the first quarter of 2023, we no longer recognize revenue from the Hilli , decreasing revenue in the Ships segment. Additionally the charters for four vessels concluded in 2023, lowering vessel revenue for the nine months ended September 30, 2024. We are now utilizing these vessels in our operations. 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, management fees and costs to operate the Hilli prior to the Hilli Exchange discussed above. 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 remained consistent during the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. There were no changes to the vessels that comprise the Ships segment in the third quarter of 2024. Vessel operating expenses decreased $17.1 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023 . The decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the disposition our investment in the common units of Hilli LLC at the end of the first quarter of 2023. During 2024, we started using four vessels that were in the Ships segment in 2023 in our terminal operations, resulting in lower vessel operating costs. 53 Table of Contents Other operating results Three Months Ended, Nine Months Ended, (in thousands of $) September 30, 2024 June 30, 2024 Change September 30, 2024 September 30, 2023 Change Selling, general and administrative $ 82,388 $ 70,578 $ 11,810 $ 223,720 $ 157,048 $ 66,672 Transaction and integration costs 3,154 1,760 1,394 6,285 4,787 1,498 Depreciation and amortization 35,364 37,413 (2,049) 123,268 125,160 (1,892) Asset impairment expense 1,484 4,272 (2,788) 5,756 — 5,756 Loss on sale of assets, net — — — 77,140 — 77,140 Total operating expenses 122,390 114,023 8,367 436,169 286,995 149,174 Operating income 79,537 44,328 35,209 308,369 607,783 (299,414) Interest expense 71,107 80,399 (9,292) 228,850 200,891 27,959 Other (income) expense, net (5,836) 47,354 (53,190) 60,630 16,150 44,480 Loss on extinguishment of debt — — — 9,754 — 9,754 Income before income from equity method investments and income taxes 14,266 (83,425) 97,691 9,135 390,742 (381,607) Income (loss) from equity method investments — — — — 12,738 (12,738) Tax (benefit) provision 2,953 3,435 (482) 28,012 69,476 (41,464) Net income $ 11,313 $ (86,860) $ 98,173 $ (18,877) $ 334,004 $ (352,881) 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 $11.8 million for the three months ended September 30, 2024, compared to the three months ended June 30, 2024. The Company incurred payroll severance cost of $7.9 million and additional share-based compensation expense of $2.5 million during the three months ended September 30, 2024. Selling, general and administrative increased $66.7 million for the nine months ended September 30, 2024 as compared to the nine months ended September 30, 2023. The increase was primarily due to increased share-based compensation expense. We recognized $47.7 million of share-based compensation expense for RSUs and other equity awards during the first three quarters of 2024; no significant cost was recognized in the first three quarters of 2023. In addition, the allowance for bad debt increased by $11.6 million due to an additional allowance recorded during the three months ended March 31, 2024. Transaction and integration costs We did not incur significant transaction and integration costs for the three or nine months ended September 30, 2024. Depreciation and amortization Depreciation and amortization decreased $2.0 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024. Depreciation and amortization decreased $1.9 million for the nine months ended 54 Table of Contents September 30, 2024 as compared to the nine months ended September 30, 2023. The Company classified the Miami Facility as held for sale on June 30, 2024, and no depreciation was recorded after that date. Asset impairment expense The Company recognized an impairment of $ 5.3 million that was predominately due to the classification of the Miami Facility as held for sale in the second quarter of 2024. There was no significant impairment of assets during the three months ended September 30, 2024. Loss on sale of assets, net During the three months ended March 31, 2024, the Company recognized a loss of $77.5 million from the sale of turbines and related equipment to the PREPA. We did not have any losses on sales during the three months ended September 30, 2024. Interest expense Interest expense decreased by $9.3 million for the three months ended September 30, 2024 as compared to the three months ended June 30, 2024, primarily due to increased capitalization of interest costs. Interest expense increased by $28.0 million for the nine months ended September 30, 2024 , as compared to the nine months ended September 30, 2023 . The increase was primarily due to an increase in total principal outstanding due to additional borrowings and amortization of related debt issuance costs. The total principal balance on outstanding facilities was $8.2 billion as of September 30, 2024 as compared to total principal outstanding of $6.2 billion as of September 30, 2023. We capitalize a significant portion of our borrowing costs for development projects, and while the principal balances increased, the interest expense did not increase as significantly. Other (income) expense, net Other (income) expense, net was $(5.8) million and $47.4 million three months ended September 30, 2024, and June 30, 2024, respectively. Other (income) expense, net was $60.6 million and $16.2 million for the nine months ended September 30, 2024 and September 30, 2023, respectively. Other income recognized in the three months ended September 30, 2024 was primarily comprised of foreign currency gains due to remeasurement of USD denominated debt in our Brazil subsidiary. The gains were partly offset by realized loss on settlement of foreign currency derivative contracts. Other expense recognized in the nine months ended September 30, 2024 was primarily comprised of foreign currency remeasurement losses and loss on termination of leases of turbines used in the grid stabilization project in Puerto Rico partially offset by interest income. Loss on extinguishment of debt During the three months ended March 31, 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes. We also recognized a premium over the repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes. We did not have any extinguishment transactions in the third quarter of 2024 or the first three quarters of 2023. Income (loss) from equity method investments During 2023, we recognized income of $6.3 million from our equity method investment in Energos and $6.0 million of income from our investment in the common units of Hilli LLC for the period prior to the completion of the disposition of 55 Table of Contents this investment. In the first quarter of 2024, we sold substantially all of our stake in Energos resulting in no income or loss from equity method investments for the three or nine months ended September 30, 2024. Tax provision We recognized a tax provision for the three months ended September 30, 2024 of $3.0 million compared to a tax provision of $3.4 million for the three months ended June 30, 2024. We recognized a tax provision of $28.0 million for the nine months ended September 30, 2024 compared to $69.5 million for the nine months ended September 30, 2023. The decrease in the tax provision for the three and nine months ended September 30, 2024 is mainly due to pre-tax losses in the US and decrease in pre-tax income in foreign jurisdictions which resulted in correlative changes in tax expense in those jurisdictions. 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 financial results do not reflect our Fast LNG solution which we expect will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the nine months ended September 30, 2024. We anticipate that the deployment of Fast LNG liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers. Though the commissioning of these facilities, particularly our first Fast LNG unit, was delayed from the initially anticipated date, which impacted our results of operations in this period and may impact our results in future periods, we began to produce LNG from our first Fast LNG unit in July 2024. The first full cargo was loaded onto the Energos Princess vessel and set sail for Europe on September 30, 2024. We plan to leverage the development process for the first unit in deploying future Fast LNG liquefaction facilities. • Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the three and nine months ended September 30, 2024 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant and certain industrial end-users. We have completed construction of our Barcarena Facility and Santa Catarina Facility and are in the final stages of commissioning these assets. We are also continuing to develop our Barcarena Power Plant, PortoCem Power Plant, Puerto Sandino Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects. Additionally, we began to deliver power to the Puerto Rican grid as part of the grid stabilization project in the second quarter of 2023. In the first quarter of 2024, our contract was terminated and assets related to the grid stabilization project were sold to PREPA. Under our new island-wide gas sale agreement with PREPA, we continue to supply gas to these power generation assets. • Our historical financial results include the results from our investments in the common units of Hilli LLC and Energos. On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of our investment in the common units of Hilli LLC (“Hilli Common Units”), disponent owner and operator of the Hilli Episeyo (the “ Hilli ”) through its subsidiary Golar Hilli Corporation, in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"). As a result of this transaction, we no longer have any ownership interest in the Hilli , and their results are no longer included in NFE's results of operations. In February 2024, the Company completed the sale of substantially all of its stake in Energos for a total consideration of $136.4 million and retaining an investment in Energos valued at $1.0 million . As a result of this transaction, we no longer include the results of Energos in our results of operations. Liquidity and Capital Resources On September 30, 2024, we entered into a Transaction Support Agreement with certain holders of our 2025 Notes, 2026 Notes and 2029 Notes, setting forth the terms of a series of transactions intended to extend the maturity profile of our indebtedness, while providing additional operating liquidity and financial flexibility. On November 6, 2024, we entered 56 Table of Contents into the Exchange and Subscription Agreement with these Supporting Holders, which sets forth the definitive terms of the Transactions, the consummation of which remains subject to customary closing conditions. We intend to use the proceeds of the Transactions to: (a) redeem in full the 2025 Notes; (b) exchange and cancel approximately $1.4 billion aggregate principal amount of 2026 Notes and 2029 Notes on a dollar-for-dollar basis for additional New Notes and (c) pay fees and expenses related to the Transactions and (d) add approximately $300 million in cash to our balance sheet. See “Recent Developments” for additional detail regarding the Transactions. The $875.0 million aggregate outstanding principal amount of our 2025 Notes matures on September 15, 2025. If any of the 2025 Notes remain outstanding 60 days prior to this maturity date (the "Springing Maturity Date"), the outstanding principal under the Revolving Facility, Term Loan B and Term Loan A (defined below) will become immediately due. In the absence of closing the Transactions, our current liquidity and forecasted cash flows from operations are not sufficient to support the repayment of the 2025 Notes, in full, prior to the Springing Maturity Date, and as such, management concluded that substantial doubt exists related to our ability to continue as a going concern. Management expects all conditions precedent to be achieved and the Transactions to close in the coming weeks, which will alleviate the substantial doubt. However, there can be no assurance that we will be successful in closing the Transactions. We intend to use a portion of the proceeds from the New Notes to redeem all of the outstanding 2025 Notes. We have issued a notice of redemption conditioned on the closing of the Transactions; we expect to effectuate the redemption, and satisfy and discharge the indenture governing the 2025 Notes, shortly following the closing of the Transactions. In addition to cash received from the recent Equity Offering and the Transactions, we expect our current working capital position to improve based on the following: (1) expected cash flows generated from new gas sale agreements and volume growth in Puerto Rico, Mexico and Brazil (2) sales of our own LNG generated by our first deployed Fast LNG unit; (3) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil and we have commitments to fund substantially all of the remaining cost of our onshore FLNG project at Altamira; (4) we have agreed to issue the New Brazil Notes to provide additional financing to construct our PortoCem Power Plant; (5) our relationships with certain significant vendors, including vendors constructing our Fast LNG assets, have allowed us to extend our payment terms to better align with the expected completion of our first Fast LNG project; and (6) the anticipated sale of our Miami Facility in the fourth quarter of 2024. In addition, we have begun to identify strategic partners for one or more of our primary businesses and expect to explore potential strategic partner financing, commercial ventures or assets sales to enhance our liquidity and financial flexibility. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash generated from certain sales and financing transactions and cash generated from operations . We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions. The terms and conditions of our indebtedness include restrictive covenants that limit our ability to operate our business, incur or refinance our debt, engage in certain transactions, and require us to maintain certain financial ratios, among others, any of which may limit our ability to finance future operations and capital needs, react to changes in our business and in the economy generally, and to pursue business opportunities and activities. Following the completion of Amendments and the Transactions, our ability to undertake these activities, including our ability to incur or refinance our debt, will be further limited. Furthermore, the restrictions contemplated by certain of the Amendments require proceeds of certain asset sales to be used to pay down existing indebtedness. From time to time, we may seek to repay, refinance or restructure all or a portion of our debt or to repurchase our outstanding debt through, as applicable, tender offers, redemptions, exchange offers, open market purchases, privately negotiated transactions or otherwise. Such transactions, if any, will depend on a number of factors, including prevailing market conditions, our liquidity requirements and contractual requirements (including compliance with the terms of our debt agreements), among other factors. Our expectations of future liquidity needs and sources include numerous assumptions that are subject to various risks and uncertainties. Refer to Note 2 – “Significant Accounting Policies” for further information on liquidity and “Item 1A. Risk Factors” for risks and uncertainties that may cause our results to differ from our expectations, each in our Annual Report on Form 10-K. Our remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, is approximately $1,362 million and includes remaining expenditures to complete our first Fast LNG project and our onshore liquefaction project at Altamira, as well as committed expenditures necessary to complete the Puerto Sandino Facility, Barcarena and PortoCem Power Plants. This does not include any capital expenditures related to Klondike. We have secured financing commitments to continue to develop our onshore Altamira project, Barcarena Power Plant and PortoCem Power Plant, 57 Table of Contents which represents approximately $942 million of our upcoming committed capital expenditures and includes upcoming long-term permanent financing in Brazil to fully fund all development costs of our PortoCem Power Plant. This anticipated financing, as well as the New Brazil Notes, is included within our secured financing commitments. We expect fully completed Fast LNG units to cost between $1.0 billion and $2.0 billion per unit on average. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to construct the Fast LNG units allow us to closely control the timing of our spending and construction schedules so that we can complete each project in time frames to meet our business needs. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments. As of September 30, 2024, we have spent approximately $128.6 million to develop the Pennsylvania Facility. Approximately $22.5 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106.1 million, has been capitalized, and to date, we have repurposed approximately $16.8 million of engineering and equipment to our Fast LNG project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities. Contractual Obligations We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations, including principal and interest, in place as of September 30, 2024. (in thousands of $) Total Less than Year 1 Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 11,486,292 $ 310,241 $ 4,949,877 $ 2,440,063 $ 3,786,111 Purchase obligations 14,298,595 478,455 2,022,043 935,826 10,862,271 Lease obligations 868,211 51,122 268,236 220,254 328,599 Total $ 26,653,098 $ 839,818 $ 7,240,156 $ 3,596,143 $ 14,976,981 Long-term debt obligations For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report, and “—Long-Term Debt and Preferred Stock” . The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of September 30, 2024. 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. The New Notes issued pursuant to the Transactions will bear interest at the increased rate of 12.00% per annum compared with the 2025 Notes, the 2026 Notes and the 2029 Notes being refinanced, and will increase long-term debt obligations. As the Transactions have not yet been completed, the increased debt and interest expense has not been included in 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, 58 Table of Contents and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of September 30, 2024. We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility, Barcarena Power Plant and PortoCem Power Plant. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued. Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, and a land lease. Cash Flows The following table summarizes the changes to our cash flows for the nine months ended September 30, 2024 and 2023, respectively : Nine Months Ended September 30, (in thousands of $) 2024 2023 Change Cash flows from: Operating activities $ 146,200 $ 537,184 $ (390,984) Investing activities (1,308,554) (2,065,562) 757,008 Financing activities 1,100,877 924,072 176,805 Net decrease in cash, cash equivalents, and restricted cash $ (61,477) $ (604,306) $ 542,829 Cash provided by operating activities Our cash flow provided by operating activities was $146.2 million for the nine months ended September 30, 2024, which increased by $391.0 million from cash provided by operating activities of $537.2 million for the nine months ended September 30, 2023. Our net income for the nine months ended September 30, 2024, when adjusted for non-cash items, decreased by $150.7 million from the nine months ended September 30, 2023. The remaining decrease in cash provided by operating activities for the nine months ended September 30, 2024 was primarily driven by increases to recoverable taxes presented in Other current assets, and decreases in accrued liabilities. We also settled a commodity swap during the first quarter of 2023, resulting in a significant cash inflow that did not recur during 2024. Cash (used in) investing activities Our cash flow used in investing activities was $1,308.6 million for the nine months ended September 30, 2024, which decreased by $757.0 million from cash used in investing activities of $2,065.6 million for the nine months ended September 30, 2023. Cash outflows for investing activities during the nine months ended September 30, 2024 were used primarily 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 of $306.6 million from the sale of turbines and related equipment to PREPA, $136.4 million from the sale of our equity method investment in Energos and $22.4 million from the sale of the Mazo . Cash outflows for investing activities during the nine months ended September 30, 2023 were used primarily for continued development of our Fast LNG project and assets to service the grid stabilization project in Puerto Rico. Cash outflows were offset by proceeds of $100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange, as well as proceeds received from the sale of the Spirit and a portion of our investment in equity securities. 59 Table of Contents Cash provided by financing activities Our cash flow provided by financing activities was $1,100.9 million for the nine months ended September 30, 2024, which increased by $176.8 million from cash provided by financing activities of $924.1 million for the nine months ended September 30, 2023. Throughout the first nine months of 2024, we had total borrowings of $3,594.2 million, with such borrowings primarily used to fund continued development of the Fast LNG project, Barcarena Power Plant, and PortoCem Power Plant. Such borrowings were also used to repay a portion of the 2025 Notes and various asset level financings in Puerto Rico and Brazil. We also repaid our Revolving Facility and short-term borrowings under repurchase agreements, prior to again drawing on these facilities. Our cash flow provided by financing activities for the nine months ended September 30, 2023 included a dividend payment of $626.3 million that was made in January 2023. Throughout the first nine months of 2023, we also borrowed under our expanded Revolving Facility, Bridge Term Loans, Equipment Notes, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $1,768.7 million. Such borrowings were primarily used to fund the ongoing development of our Fast LNG project and to support our grid stabilization project in Puerto Rico. Increased borrowings during 2023 were offset by repayments of debt totaling $104.5 million, primarily the repayment of short-term borrowings under repurchase arrangements. Long-Term Debt and Preferred Stock The terms of our debt instruments and associated obligations have been described in our Annual Report. There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below and as contemplated under "Recent Developments". 2029 Senior Secured 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 2025 Notes and 2026 Notes, and the 2029 Notes are secured by substantially the same collateral as the first lien obligations under the 2025 Notes and 2026 Notes. The 2029 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain conditions and qualifications. The 2029 Notes also provide for customary events of default and prepayment provisions. In connection with the offering of the 2029 Notes, we completed a cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes, for an aggregate repurchase price of $376.9 million. The tender offer was closed and the partial repurchase of the 2025 Notes was completed in the first quarter of 2024. The premium over the repurchase price of $1.9 million was recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) . BNDES Term Loan One of our subsidiaries, the owner of t he Barcarena Power Plant, entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). We are able to borrow up to $355.6 million under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"). In the first quarter of 2024, we borrowed $284.4 million under the BNDES Credit Agreement. In the third quarter of 2024, we borrowed $60.3 million under the BNDES Credit Agreement. Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045. Interest payments prior to April 2026 are made through an increase in the outstanding principal amount and are due quarterly thereafter. The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's power purchase agreements. These Brazilian subsidiaries must adhere to customary affirmative and negative 60 Table of Contents covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions. Proceeds received were used to repay the existing Barcarena Term Loan (defined in the Annual Report) and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025. In February 2024, we repaid the full outstanding principal balance of the Barcarena Term Loan, fully extinguishing the obligation. No material loss on extinguishment was recognized in conjunction with this repayment. 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 our green hydrogen facility, and we have provided a guarantee of the obligations under the EB-5 Loan Agreement. In the nine months ended September 30, 2024, an additional $37.1 million was funded under the EB-5 Loan Agreement. PortoCem Financings As part of the PortoCem Acquisition, we assumed a term loan in the aggregate principal amount of R$141.4 million ($28.1 million based on rates in effect on the acquisition date) due December 2024, bearing interest at a rate equal to the one-day interbank deposit rate in Brazil plus 5.0% (the “PortoCem BTG Loan”). Lenders under the PortoCem BTG Loan waived acceleration requirements in the event of a change in control in conjunction with the PortoCem Acquisition, and repayment of the PortoCem BTG Loan was required upon the earlier of PortoCem obtaining additional financing or the original maturity date of December 2024. In April 2024, PortoCem and a syndicate of banks in Brazil entered into a commitment letter for R$2.9 billion of financing. PortoCem received funding under a short term credit note of R$600.0 billion million ("PortoCem Credit Note") from this syndicate that was due in July 2024, and a portion of the proceeds was used to repay the PortoCem BTG Loan. In May 2024, the PortoCem Credit Note was replaced by a bridge financing agreement that allows PortoCem to borrow up to R 2.9 billion due in October 2025 ("PortoCem Bridge Loan"). PortoCem initially borrowed R$ 1.5 billion ($ 275.3 million based on rates in effect at September 30, 2024), and this initial funding was used to repay the PortoCem Credit Note and to begin the development and construction of the PortoCem Power Plant. The PortoCem Bridge Loan bears interest at the one-day interbank deposit futures rate in Brazil plus 4.25% , and no principal payments are required until maturity in October 2025. The PortoCem Bridge Loan contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The PortoCem Bridge Loan does not contain any restrictive financial covenants. Turbine Financing In May 2024, we executed a loan agreement with a lender to borrow $148.5 million million under a promissory note secured by certain of our turbines (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. Equipment Notes In conjunction with the execution of the APA to sell certain turbines to PREPA in March 2024, we repaid the Equipment Notes in full, releasing any liens held on the turbines prior to their sale. Principal outstanding as of the repayment date was $188.4 million, and we incurred a prepayment premium of 3%. The prepayment premium and any 61 Table of Contents unamortized financing costs of $7.9 million were recognized as Loss on extinguishment of debt, net in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss). Term Loan A 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"). Proceeds will be used to pay costs of the construction and development of our onshore FLNG project in Altamira (the “Altamira Onshore Project”). The initial and subsequent funding of the Term Loan A was subject to certain conditions, including the condition to the initial funding that initial generation of LNG from the offshore FLNG facility at Altamira ("FLNG1 Project") had been achieved. Such condition was satisfied and initial funding occurred in the third quarter of 2024. The remaining commitments for subsequent funding expire on the earliest of June 30, 2026, the date of completion of the Onshore Altamira Project (the “Completion Date”) and the date that the commitments are reduced to zero or terminated. During the third quarter of 2024, we drew $285.8 million on the Term Loan A. 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 2025 Notes, 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 FLNG1 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 FLNG1 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 the Onshore Altamira Project. 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 maturity date. In the event that the our existing 2025 Notes or 2026 Notes are not refinanced or repaid at least 60 days prior to their respective maturities, 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 the Onshore Altamira Project. Additionally, commencing with the first fiscal quarter after the Completion Date, we will be required to prepay the Term Loan A with the Onshore Altamira Project’s Excess Cash Flow (as defined in the Term Loan A Credit Agreement). The Term Loan A will bear interest at a per annum rate equal to Term SOFR plus 3.75%, or at a base rate of 2.75%. The interest rate on the Term Loan A will increase by 0.25% every 180 days beginning in June 2025. The Term Loan A Credit Agreement contains usual and customary representations, warranties and affirmative and negative covenants for financings of this type, including certain representations and warranties related to the Onshore Altamira Project. The Term Loan A Credit Agreement includes certain other covenants related solely to the Onshore Altamira Project, including limitations on capital expenditures, restrictions on additional accounts, and restrictions on amendments or termination of certain material documents related to the Onshore Altamira Project. We must also comply with certain financial covenants. Debt and lease restrictions We are required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 4.0:1.0. On August 31, 2024, we entered into amendments of certain debt agreements that amend and restate the conditions applicable to the suspension of the maximum Debt to Total Capitalization Ratio for the quarterly covenant tests conducted as of the last day of the fiscal quarters ending September 30, 2024, December 31, 2024 and March 31, 2025. The amended agreements also contain a financial covenant that requires a minimum consolidated liquidity of (i) $50.0 million as of the last day of each month, commencing as of October 31, 2024 and (ii) $100.0 million as of the last day of any fiscal quarter, commencing as of December 31, 2024. We were in compliance with all covenants as of September 30, 2024 . 62 Table of Contents Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of September 30, 2024 , there have been no significant changes to our critical accounting estimates since our Annual Report. Recent Accounting Standards For descriptions of recently issued accounting standards, see Note 3 to our notes to condensed consolidated financial statements included elsewhere in this Quarterly Report.