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. 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 Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, the 34 Table of Contents 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 35 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. We executed the final long-form gas sales agreement in the second quarter of 2023, which is subject to certain conditions precedent including the execution of the final agreement to sell the La Paz Power Plant. 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 third 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 commence production from our own Fast LNG facilities, the first of which began to produce LNG in July 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 Sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed 36 Table of Contents 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 will utilize 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 a 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. 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 infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks. 37 Table of Contents 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 expect to commence operations, including delivery to the Alunorte Alumina Refinery in the second half of 2024. 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 expect to complete commissioning of our Santa Catarina Facility and commence operations in the second half of 2024. Ireland Facility 38 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 are challenging this decision. 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 and expect to commence operations on the first phase in 2025. 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. Recent Developments The Company 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. 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. 39 Table of Contents 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. Results of Operations – Three Months Ended June 30, 2024 compared to Three Months Ended March 31, 2024 and Six Months Ended June 30, 2024 compared to Six Months Ended June 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 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. 40 Table of Contents The tables below present our segment information for the three months ended June 30, 2024 and March 31, 2024, and for the six months ended June 30, 2024 and June 30, 2023: 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 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 Three Months Ended March 31, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 647,737 $ 42,584 $ 690,321 $ — $ 690,321 Cost of sales (2) $ 229,117 — 229,117 — 229,117 Vessel operating expenses (4) — 8,396 8,396 — 8,396 Operations and maintenance (4) $ 68,548 — 68,548 — 68,548 Segment Operating Margin $ 350,072 $ 34,188 $ 384,260 $ — $ 384,260 Three Months Ended March 31, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 333,769 Depreciation and amortization 50,491 Consolidated Segment Operating Margin (Non-GAAP) $ 384,260 41 Table of Contents Six Months Ended June 30, 2024 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 1,033,165 $ 85,162 $ 1,118,327 $ — $ 1,118,327 Cost of sales (1)(2) 450,977 — 450,977 — 450,977 Vessel operating expenses (4) — 16,899 16,899 — 16,899 Operations and maintenance (4) 107,840 — 107,840 — 107,840 Deferred earnings from contracted sales (5) 90,000 — 90,000 (90,000) — Segment Operating Margin $ 564,348 $ 68,263 $ 632,611 $ (90,000) $ 542,611 Six Months Ended June 30, 2024 (in thousands of $) Consolidated Gross margin (GAAP) $ 454,707 Depreciation and amortization 87,904 Consolidated Segment Operating Margin (Non-GAAP) $ 542,611 Six Months Ended June 30, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 998,112 $ 163,758 $ 1,161,870 $ (21,394) $ 1,140,476 Cost of sales (1)(2) 296,169 — 296,169 114,537 410,706 Vessel operating expenses (4) — 30,682 30,682 (5,948) 24,734 Operations and maintenance (4) 60,368 — 60,368 — 60,368 Segment Operating Margin $ 641,575 $ 133,076 $ 774,651 $ (129,983) $ 644,668 Six Months Ended June 30, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 568,178 Depreciation and amortization 76,490 Consolidated Segment Operating Margin (Non-GAAP) $ 644,668 (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 gains of $141.9 million for the six months ended June 30, 2023 were recognized as a reduction to Cost of sales in the segment measure. No such transactions were completed in 2024. The Company recognized unrealized losses of $108.3 million on the mark-to-market value of derivative transactions for the six months ended June 30, 2023, and these losses reconcile Cost of sales in the segment measure to Cost of sales in the Condensed Consolidated Statements of Operations and Comprehensive Income (Loss) . The Company has 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 six months ended June 30, 2023 are shown as a reduction to Cost of sales in the segment measure. 42 Table of Contents (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 on contracted LNG sales of $90,000. The effective share of revenues, expenses and operating margin attributable to the Company's 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 in the third and fourth quarters of 2024. Terminals and Infrastructure Segment Three Months Ended, (in thousands of $) June 30, 2024 March 31, 2024 Change Total revenues $ 385,428 $ 647,737 $ (262,309) Cost of sales (exclusive of depreciation and amortization) 221,860 229,117 (7,257) Operations and maintenance 39,292 68,548 (29,256) Deferred earnings from contracted sales 90,000 — 90,000 Segment Operating Margin $ 214,276 $ 350,072 $ (135,796) Six Months Ended, (in thousands of $) June 30, 2024 June 30, 2023 Change Total revenues $ 1,033,165 $ 998,112 $ 35,053 Cost of sales (exclusive of depreciation and amortization) 450,977 296,169 154,808 Operations and maintenance 107,840 60,368 47,472 Deferred earnings from contracted sales 90,000 — 90,000 Segment Operating Margin $ 564,348 $ 641,575 $ (77,227) Total revenue Total revenue for the Terminals and Infrastructure Segment decreased by $262.3 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. The decrease was primarily driven by decreases to revenue earned in our Puerto Rican operations after the termination of our contract to support the grid stabilization project late in the first quarter of 2024. Additionally, volumes delivered to downstream terminal customers decreased from 22.0 TBtu in the first quarter of 2024 to 20.2 TBtu in the second quarter of 2024, which was primarily due to contract termination and maintenance in our Puerto Rico operations. The average Henry Hub index pricing used to invoice our downstream customers decreased by 15% for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. Total revenue for the Terminals and Infrastructure Segment increased by $35.1 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023, and the increase in revenue was primarily attributable to the following: • For the six months ended June 30, 2024, volumes delivered to downstream customers were 42.1 TBtu as compared to 26.1 TBtu for the six months ended June 30, 2023. We delivered gas for two and half months for the 43 Table of Contents grid stabilization project in Puerto Rico during the first half of 2024, while the project was just ramping up during the second quarter of 2023. • In the third quarter of 2023, we started providing operations and maintenance services to PREPA's thermal generation assets recognizing $109.6 million of revenue during the six months ended June 30, 2024. 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 25% for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. • The Company had $24.5 million in cargo sales for the six months ended June 30, 2024. Revenue from cargos sales was $617.1 million for the six months ended June 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 decreased by $7.3 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024, which was attributable to lower cost of gas purchased and volumes delivered. We delivered 8% less volumes to our downstream terminal customers during the three months ended June 30, 2024 compared to the three months ended March 31, 2024. Our cost to deliver natural gas volumes decreased to $6.42 per MMBtu for the three months ended June 30, 2024 from $6.96 per MMBtu for the three months ended March 31, 2024. After our FLNG asset is fully commissioned and operational, we expect to be able to produce materially cheaper LNG than the LNG purchased under our supply contracts. Cost of sales increased by $154.8 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023, which was attributable to the following activity: • In the six months ended June 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. • We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $71.1 million during the six months ended June 30, 2024 due to increased volumes delivered. We delivered 61% 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, decreasing to $6.65 per MMBtu for the six months ended June 30, 2024 from $7.66 per MMBtu for the six months ended June 30, 2023. • Vessel costs increased by $47.3 million, for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. In 2023, we chartered additional vessels to enable us to rapidly have the infrastructure available to deliver additional LNG to Puerto Rico to support the grid stabilization contract. In future periods, we expect our vessel costs to decrease as we optimize our supply chain to Puerto Rico with fewer and less costly vessels. We were also able to sub-charter certain vessels for a portion of the current period, earning incremental charter revenue. 44 Table of Contents • We recognized additional payroll and other operating costs of $47.6 million to provide services under Genera's operations and maintenance contract; these costs are passed onto PREPA. No such costs were incurred during the six months ended June 30, 2023 as our contract commenced on July 1, 2023. • We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $162.2 million during the six months ended June 30, 2024 as our LNG cargo sale activity has been significantly lower in the first half of 2024. The weighted-average cost of our LNG inventory balance to be used in our operations as of June 30, 2024 and December 31, 2023 was $7.30 per MMBtu and $8.09 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 $29.3 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. The decrease was primarily attributable to reduced operations, maintenance and lease costs of turbines to generate power as part of the grid stabilization project in Puerto Rico. In conjunction with the sale of certain turbines to PREPA, we have terminated our leases of certain turbines and are no longer incurring costs to operate these turbines. Operations and maintenance increased $47.5 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023 . The increase was primarily due to additional operations and maintenance cost including lease of turbines as part of the grid stabilization project in Puerto Rico. The project operated for two and a half months during the first half of 2024, while it was just ramping up during the second quarter of 2023. Deferred earnings from contracted sales In the second quarter of 2024, we completed forward sales receiving a prepayment from the buyer of $90.0 million. 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 for the second quarter of 2024. 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 third and fourth quarters 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 $) June 30, 2024 March 31, 2024 Change Total revenues $ 42,578 $ 42,584 $ (6) Vessel operating expenses 8,503 8,396 107 Segment Operating Margin $ 34,075 $ 34,188 $ (113) Six Months Ended, (in thousands of $) June 30, 2024 June 30, 2023 Change Total revenues $ 85,162 $ 163,758 $ (78,596) Vessel operating expenses 16,899 30,682 (13,783) Segment Operating Margin $ 68,263 $ 133,076 $ (64,813) Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of June 30, 2024 , three FSRUs and one LNG carrier were leased to customers under long-term arrangements. 45 Table of Contents 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 remained consistent for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024 . Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of certain vessels included in the transaction, and as such, we continue to recognize revenue from the charter of these vessels to third parties. Total revenue for the Ships segment decreased $78.6 million for the six months ended June 30, 2024 as compared to the six months ended June 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 six months ended June 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 June 30, 2024 as compared to the three months ended March 31, 2024. There were no changes to the vessels that comprise the Ships segment in the second quarter of 2024. Vessel operating expenses decreased $13.8 million for the six months ended June 30, 2024 as compared to the six months ended June 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. 46 Table of Contents Other operating results Three Months Ended, Six Months Ended, (in thousands of $) June 30, 2024 March 31, 2024 Change June 30, 2024 June 30, 2023 Change Selling, general and administrative $ 70,578 $ 70,754 $ (176) $ 141,332 $ 107,941 $ 33,391 Transaction and integration costs 1,760 1,371 389 3,131 2,048 1,083 Depreciation and amortization 37,413 50,491 (13,078) 87,904 76,490 11,414 Asset impairment expense 4,272 — 4,272 4,272 — 4,272 Loss on sale of assets, net — 77,140 (77,140) 77,140 — 77,140 Total operating expenses 114,023 199,756 (85,733) 313,779 186,479 127,300 Operating income 44,328 184,504 (140,176) 228,832 458,189 (229,357) Interest expense 80,399 77,344 3,055 157,743 136,069 21,674 Other expense (income), net 47,354 19,112 28,242 66,466 18,421 48,045 Loss on extinguishment of debt — 9,754 (9,754) 9,754 — 9,754 Income before income from equity method investments and income taxes (83,425) 78,294 (161,719) (5,131) 303,699 (308,830) Income (loss) from equity method investments — — — — 12,249 (12,249) Tax provision (benefit) 3,435 21,624 (18,189) 25,059 44,282 (19,223) Net income $ (86,860) $ 56,670 $ (143,530) $ (30,190) $ 271,666 $ (301,856) 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 remained consistent for the three months ended June 30, 2024, compared to the three months ended March 31, 2024. The Company incurred increased share-based compensation expense, that were partially offset by decrease in bad debt expense. We recognized an additional $14.7 million of share-based compensation expense for RSUs and other equity awards during the second quarter of 2024 as we recognized a full quarter of expense for RSUs granted during the first quarter of 2024. During the first quarter of 2024, the Company recorded an additional allowance for uncollectible receivables of $11.6 million. There was no such allowance recognized during the second quarter of 2024. We also incurred lower payroll and professional fees in the second quarter of 2024. Selling, general and administrative increased by $33.4 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. The increases were primarily due to increased share-based compensation expense. We recognized $25.2 million of share-based compensation expense for RSUs and other equity awards during the first half of 2024; no significant cost was recognized in the first half 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 six months ended June 30, 2024 or six months ended June 30, 2023. 47 Table of Contents Depreciation and amortization Depreciation and amortization decreased $13.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. We sold certain turbines and equipment to PREPA in the first quarter of 2024, and the decrease in depreciation was primarily a result of no longer owning these assets. Depreciation and amortization increased $11.4 million for the six months ended June 30, 2024 as compared to the six months ended June 30, 2023. In 2023, we began to place assets in service as part of the grid stabilization project in Puerto Rico, including turbines leased for the Palo Seco Power Plant under a finance lease. The increase is primarily resulting from depreciation of the leasehold improvements that were placed into service during the second and third quarters of 2023, prior to the sale of these assets in the first quarter of 2024. Asset impairment expense In December 2023, the Company recognized an impairment of $4.3 million in conjunction with the classification as the Miami Facility as held for sale in the second quarter of 2024. There was no impairment of assets during three months ended March 31, 2024 or six months ended June 30, 2023. 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 June 30, 2024 or six months ended June 30, 2023. Interest expense Interest expense increased by $3.1 million for the three months ended June 30, 2024 as compared to the three months ended March 31, 2024. We have incremental borrowings under the PortoCem Bridge Loan and our new Turbine Financing (each as defined below), and much of this increased interest expense was capitalized. Interest expense increased by $21.7 million for the six months ended June 30, 2024 , as compared to the six months ended June 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 $7.8 billion as of June 30, 2024 as compared to total principal outstanding of $5.5 billion as of June 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 expense (income), net Other expense (income), net was $47.4 million and $19.1 million for the three months ended June 30, 2024, and March 31, 2024, respectively. Other expense (income), net was $66.5 million and $18.4 million for the six months ended June 30, 2024 and 2023, respectively. Other expense recognized in the three months ended June 30, 2024 was primarily comprised of foreign currency losses due to remeasurement of USD denominated debt in our Brazil subsidiary. Other expense recognized in the six months ended June 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 48 Table of Contents 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 second quarter of 2024 or the first half of 2023. Income (loss) from equity method investments During the first half of 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 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 six months ended June 30, 2024. Tax provision We recognized a tax provision for the three months ended June 30, 2024 of $3.4 million compared to a tax provision of $21.6 million for the three months ended March 31, 2024. We recognized a tax provision of $25.1 million for the six months ended June 30, 2024 compared to a tax provision of $44.3 million for the six months ended June 30, 2023. The decrease in the tax provision for the three and six months ended June 30, 2024 is mainly due to changes in pre-tax income in the US and 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 99% of our LNG volumes from third parties for the six months ended June 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. 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 six months ended June 30, 2024 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Power Plant, certain industrial end-users and our Miami Facility. While we anticipate the sale of our Miami Facility in the third quarter of 2024, we have completed construction and commissioning of our Barcarena Facility and Santa Catarina Facility and expect to place these assets into service in 2024. We are also continuing to develop our 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. 49 Table of Contents Liquidity and Capital Resources We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. Our 2025 Notes mature 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 FLNG2 Term Loans (as defined within Note 26 to the financial statements) will become immediately due. The aggregate principal amount of 2025 Notes outstanding as of June 30, 2024 is $875,000. We have entered into a Backstop Agreement with a lender, pursuant to which we may, at our sole option, issue and sell to this lender (subject to the satisfaction of certain conditions) senior secured notes up to an aggregate principal amount sufficient to generate gross proceeds of $875 million with a term of at least three years from the closing date within a certain window prior to the Springing Maturity Date. Proceeds received would be used to repurchase or redeem all outstanding 2025 Notes. We expect the 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) our credit agreements allow for proceeds from the sale of assets to be reinvested in our business, and we have significant non-core assets that could be used to fund our developments; (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 third quarter of 2024. In addition, we are exploring capital raising and strategic alternatives for our business in Brazil, which may include a merger transaction, sale of a minority interest and/ or initial public offering. There can be no assurance that the exploration of capital raising and strategic alternatives will result in any agreements or transactions, or that, if completed, any agreements or transactions will be successful or on attractive terms. 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. 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 is approximately $1,446 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 Facility, Barcarena and PortoCem Power Plants, and Santa Catarina Facility. This does not include any capital expenditures related to Klondike. We have secured financing commitments to continue to develop our onshore Altamira project and the Barcarena Power Plant, which represents approximately $673 million of our upcoming committed capital expenditures. We expect fully completed Fast LNG units to cost between $1.0 billion and $1.6 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. 50 Table of Contents As of June 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 June 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 $ 11,204,718 $ 456,329 $ 4,890,535 $ 2,109,742 $ 3,748,112 Purchase obligations 13,751,986 1,212,560 1,576,257 1,395,577 9,567,592 Lease obligations 912,570 93,817 269,278 220,741 328,734 Total $ 25,869,274 $ 1,762,706 $ 6,736,070 $ 3,726,060 $ 13,644,438 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 June 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. Purchase obligations We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of June 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 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. 51 Table of Contents Cash Flows The following table summarizes the changes to our cash flows for the six months ended June 30, 2024 and 2023, respectively : Six Months Ended June 30, (in thousands of $) 2024 2023 Change Cash flows from: Operating activities $ 162,968 $ 503,877 $ (340,909) Investing activities (882,715) (1,367,092) 484,377 Financing activities 735,679 222,583 513,096 Net decrease in cash, cash equivalents, and restricted cash $ 15,932 $ (640,632) $ 656,564 Cash provided by operating activities Our cash flow provided by operating activities was $163.0 million for the six months ended June 30, 2024, which decreased by $340.9 million from cash provided by operating activities of $503.9 million for the six months ended June 30, 2023. Our net income for the six months ended June 30, 2024, when adjusted for non-cash items, decreased by $175.2 million from the six months ended June 30, 2024. The remaining decrease in cash provided by operating activities for the six months ended June 30, 2024 was primarily driven by increases to receivables. We also settled a significant 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 $882.7 million for the six months ended June 30, 2024, which decreased by $484.4 million from cash used in investing activities of $1,367.1 million for the six months ended June 30, 2023. Cash outflows for investing activities during the six months ended June 30, 2024 were used primarily for continued development of our Fast LNG 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 six months ended June 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. Cash provided by financing activities Our cash flow provided by financing activities was $735.7 million for the six months ended June 30, 2024, which increased by $513.1 million from cash provided by financing activities of $222.6 million for the six months ended June 30, 2023. In the first quarter of 2024 we issued $750.0 million of 2029 Notes with such borrowings primarily used to repay $375.0 million of the 2025 Notes and repay a portion of our outstanding balance on the Revolving Facility. In advance of the sale of turbines to PREPA, we also repaid the Equipment Notes in full. Subsequently, we utilized our Revolving Facility to fund continued development of the Fast LNG project. We also received $284.4 million under the BNDES Credit Agreement, with such borrowings primarily used to repay the Barcarena Term Loan and fund development of the Barcarena Power Plant. In the second quarter of 2024, we borrowed $269.9 million to repay the PortoCem BTG Loan and begin the development and construction of a power plant to deliver under the capacity reserve contracts acquired in the PortoCem Acquisition. Additionally, we borrowed $148.5 million under a promissory note secured by certain turbines owned by the Company . Our cash flow provided by financing activities for the six months ended June 30, 2023 included a dividend payment of $626.3 million that was made in January 2023. Throughout the first six months of 2023, we also borrowed under our expanded Revolving Facility for total additional borrowings of $741.6 million, with such borrowings primarily used to fund the ongoing development of our Fast LNG project. We also borrowed $100.0 million under the Equipment Notes to support our grid stabilization project in Puerto Rico and $78.0 million of short-term borrowings under repurchase arrangements. These Equipment Notes were refinanced by the Turbine Financing. 52 Table of Contents 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. 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 the Company’s 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 The owner of our power plant under construction in Pará, Brazil (the "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. 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. 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 capacity reserve contracts. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions. Proceeds received are to be 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 significant 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 53 Table of Contents we have provided a guarantee of the obligations under the EB-5 Loan Agreement. In the six months ended June 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 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 ( $269.9 million based on rates in effect at June 30, 2024), and this initial funding was used to repay the PortoCem Credit Note and to begin the development and construction of a power plant to deliver under the capacity reserve contracts acquired in the PortoCem Acquisition. 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 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 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) . 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. We were in compliance with all covenants as of June 30, 2024. Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of June 30, 2024 , there have been no significant changes to our critical accounting estimates since our Annual Report. 54 Table of Contents 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.