New Fortress Energy Inc.
09/05/2025 | Press release | Distributed by Public on 09/05/2025 15:12
Quarterly Report for Quarter Ending June 30, 2025 (Form 10-Q)
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, 2024 (our "Annual Report") for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.
The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America ("GAAP"). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to "-Factors Impacting Comparability of Our Financial Results" for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.
Unless the context otherwise requires, references to "Company," "NFE," "we," "our," "us" or like terms refer to New Fortress Energy Inc. and its subsidiaries.
Overview
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 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. We placed our first floating liquefaction unit, which we refer to as "Fast LNG" or "FLNG", into service in the fourth quarter of 2024, and we plan to source a portion of our LNG needs from this facility. The Terminals and Infrastructure segment includes all terminal operations in Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal, logistics or sub-charter operations, which allows us to optimally manage our LNG supply and fleet.
Our Ships segment includes certain vessels which are currently chartered under long-term arrangements to third parties and are part of the Energos Formation Transaction (defined below). Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire, and these vessels are expected to be included in our Terminals and Infrastructure segment at such time.
On May 14, 2025, we completed the sale of our Jamaica business, including operations at the LNG import terminal in Montego Bay, the offshore floating storage and regasification terminal in Old Harbour and the 150 megawatt Combined Heat and Power Plant in Clarendon, along with the associated infrastructure (the "Jamaica Business") receiving net cash proceeds of approximately $678 million, with additional $99 million proceeds held in escrow and to be returned to the Company based on the terms of the sale agreement.
Our Current Operations - Terminals and Infrastructure
Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including the Puerto Rico Electric Power Authority ("PREPA") and Comisión Federal de Electricidad ("CFE"), Mexico's power utility, each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers.
San Juan Facility
Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and industrial end-user customers in Puerto Rico.
In 2023, we entered into agreements for the installation and operation of approximately 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 350MW of duel-fuel power generation using our gas supply in less than 180 days.
In March 2024, our contract to provide emergency power services to support the grid stabilization project was terminated, and we completed a series of transactions that included the sale of turbines and related equipment deployed to support the grid stabilization project to PREPA. In March 2024, we were also awarded a 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 to PREPA. The contract initially expired in March 2025. During 2025, the Company and PREPA agreed to a series of short-term extensions of the gas supply agreement while working towards a long-term solution that is in the best interests of both parties and achieves our mutual goal of sustained, efficient power generation for Puerto Rico. The gas supply agreement is currently set to expire on September 12, 2025. There can be no assurances that the long-term gas sale agreement will be executed, and to the extent the Company is not able to execute such an agreement, the Company's future results of operations could be adversely impacted and the impact could be material.
We are pursuing a $659 million request for equitable adjustment related to the early termination of our contract to provide emergency power services. 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.
In 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-year contract for the operation and maintenance of PREPA's thermal generation assets with the goal of reducing costs and improving reliability of power generation in Puerto Rico. The service period under the contract commenced on July 1, 2023, and we receive an annual management fee for the services provided.
La Paz Facility
In 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 third quarter of 2024, we executed an amendment to the gas sales agreement to multiple CFE power generation facilities in Baja California Sur on a take-or-pay basis that extended the term to 10 years from November 3, 2024, and amended the annual min/max quantities.
Santa Catarina Facility
We placed our Santa Catarina Facility in service in the fourth quarter of 2024. The Santa Catarina Facility is located on the southern coast of Brazil 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 and constructed a 33-kilometer, 20-inch pipeline that connects the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. ("TBG") pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina
Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day of natural gas.
In August 2024, we acquired 100% of the outstanding equity interest of Usina Termeletrica de Lins S.A. ("Lins"), which owns key rights and permits to develop a natural gas-fired power plant for up to 2.05GW located in the State of São Paulo, within the city limits of Lins. We expect to participate in the power auctions anticipated to occur in 2025 in Brazil, and to the extent that NFE is successful in these auctions, we plan to develop a gas-fired power plant using natural gas from the Santa Catarina Facility.
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) our own FLNG production; and 3) additional LNG supply contracts expected to commence in 2027. Our first FLNG facility began to produce LNG in July 2024, and we expect to generate up to 70 TBtu annually from this facility. When expected production from FLNG is combined with our commitments to purchase and receive physical delivery of LNG volumes, we expect to have sufficient supply for 100% of our committed volumes for each of our downstream terminals inclusive of our San Juan Facility, La Paz 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 and 2029.
Geopolitical events have substantially impacted and may continue to impact the natural gas and LNG markets, which have experienced significant 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, and 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 shipping assets include Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"). Our shipping assets are included in both of our operating segments. Certain vessels are currently chartered to third parties under long-term arrangements and are part of the Energos Formation Transaction (defined below); such vessels are included in our Ships segment. At the expiration of third party charters of these vessels, we plan to utilize these vessels for our own operational purposes. Vessels we operate at our terminal operations or that we decide to sub-charter are included in our Terminals and Infrastructure segment.
In August 2022, we completed a transaction (the "Energos Formation Transaction") with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of eleven vessels to Energos in exchange for approximately $1.85 billionin cash anda 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos.
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 ("Barcarena Facility") and power plants located in Pará, Brazil; our LNG terminal facility and power plant in Puerto Sandino, Nicaragua ("Puerto Sandino Facility"); our LNG terminal and power plant in Ireland ("Ireland Facility"), our first green hydrogen project ("ZeroPark I") and Klondike Digital Infrastructure, our 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 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.
Fast LNG is anchored by key benefits over conventional liquefaction projects. In particular, we believe installing modular equipment in a shipyard will meaningfully expedite timelines. In addition, placing solutions offshore provides greater access to natural gas and optimized marine logistics.
We describe our operational and planned FLNG projects below.
Altamira
Our first Fast LNG unit has been deployed off the coast of Altamira, Tamaulipas, Mexico, and was placed into service in the fourth quarter of 2024. The 1.4 million ton per annum ("MTPA") FLNG unit utilizes CFE's firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. This first FLNG unit has been fully commissioned, and we are in the process of increasing available liquefaction capacity through optimization projects.
We expect to deploy up to two 1.4MTPA additional FLNG units onshore at the existing Altamira LNG import facility. The terminal also would source feedgas from the CFE 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.
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
In the second quarter of 2025, we determined that it was no longer probable that we would pursue development of the Lakach deepwater offshore project and recorded an impairment of $47.3 million. No further costs associated with this project are capitalized on our Consolidated Balance Sheets.
Barcarena Facility
The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of delivering almost 600,000 MMBtu from LNG per day and storing up to
160,000 cubic meters of LNG. We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility.
The Barcarena Facility will also supply our new 630MW combined cycle natural gas-fired power plant located in Pará, Brazil (the "Barcarena Power Plant"). The power plant is fully contracted under multiple 25-year power purchase agreements to supply electricity to the national electricity grid. We expect to complete the Barcarena Power Plant 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"). PortoCem is the owner of a 15-year 1.6GW capacity reserve contract in Brazil. We havetransferred the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE is building the 1.6 GW simple cycle, natural gas-fired power plant ("PortoCem Power Plant") to supply the capacity reserve contract using gas from the Barcarena Facility. We expect the PortoCem Power Plant to be completed in 2026.
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. Construction of the terminal and power plant is substantially complete; however, we will determine timing of final commissioning and commencement under our PPA based on the most optimal use of our LNG supply chain. As part of our long-term strategy, we are also evaluating solutions to optimize power generation and delivery to other markets, connected to our power plant through a regional transmission line.
Ireland Facility
We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland's Transmission System Operator. The power plant is required to be operational by October 2026.
In the third quarter of 2023, An Bord Pleanála ("ABP"), Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We challenged this decision, and in September 2024, the High Court of Ireland ruled that ABP did not have appropriate grounds for the denial of our permit. In March 2025, APB withdrew their appeal to the September 2024 High Court decision. ABP is now reconsidering our planning application in accordance with Irish Law.
Further, in March 2025, ABP granted our application to construct a 600 MW power plant and a separate application to construct the 220 kV electricity interconnect. We are able to fuel this power plant via our LNG marine import terminal, if approved, or using gas provided from our permitted pipeline interconnection. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, which could preclude the development of this project; however, management continues to assess all options in respect of future developments for the land held.
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
In 2024, we 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 develop independent power sources that utilize and provide 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 plans to develop 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, or will 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
On July 2, 2025, we entered into a deferral agreement for our Letter of Credit Agreement. The deferral agreement deferred the date on which we were required to cash collateralize the letters of credit scheduled that would remain outstanding on or after July 24, 2025, the then-current maturity date (the "Cash Collateralization Requirement") until July 17, 2025. The Cash Collateralization Requirement was subsequently deferred in a second deferral agreement, dated July 17, 2025, until July 24, 2025.
On July 24, 2025, we entered into an extension agreement to our Letter of Credit Agreement. The extension agreement extended the maturity date to July 31, 2025 and deferred the Cash Collateralization Requirement until July 31, 2025. Pursuant to a second extension agreement on July 31, 2025, the then-current maturity date was extended to August 8, 2025 and the Cash Collateralization Requirement was deferred to August 8, 2025.
On August 8, 2025, we entered into the ninth amendment to our Letter of Credit Agreement to, among other things, (i) change the facility from uncommitted to committed; (ii) extend the maturity date to November 14, 2025; (iii) add an asset sale sweep prepayment provision; and (iv) make certain changes to fees and pricing. In addition, the commitments were reduced to approximately $195,000 and are automatically reduced on October 5, 2025 to approximately $155,000.
We do not expect to be in compliance with the consolidated first lien debt ratio or the fixed charge coverage ratio in the Letter of Credit Facility for the fiscal quarter ending September 30, 2025. If we are not compliance with these covenants and this non-compliance is not waived, the lenders have the right to require 102% cash collateralization of all letters of credit outstanding under the Letter of Credit Facility. If we do not adequately collateralize the outstanding letters of credit, certain of our outstanding indebtedness would be payable on demand.
Other Matters
On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explainwhy 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; theFERC 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, on September 26, 2024, the USCG issued a Letter of Warning in respect of our ongoing ship to ship transfers of LNG operations within the San Juan port limits. On October 21, 2024, we filed an appeal with the USCG under 33 CFR 160.7. In December 2024 and February 2025, we submitted an updated Letter of Intent and Waterway Suitability Assessments detailing our alternative operational plans to the USCG and are working collaboratively with the USCG to obtain a new Letter of Recommendation to FERC in support of our operations, which we expect to be imminently forthcoming. In concert with our collaboration with the USCG regarding our new operational plans, we withdrew our appeal on February 14, 2025.
On October 25, 2024, FERC issued a notice of intent to prepare an Environmental Impact Statement, which included, among other things, two public scoping sessions in Puerto Rico held on November 18, 2024 in accordance with the National Environmental Policy Act.
Results of Operations - Three Months Ended June 30, 2025 compared to Three Months Ended March 31, 2025 and Six Months Ended June 30, 2025 compared to Six Months Ended June 30, 2024
Performance of our two segments, Terminals and Infrastructure and Ships, is evaluated based on Segment Operating Margin. Segment Operating Margin reconciles to Consolidated Segment Operating Margin as reflected below, which is a non-GAAP measure. We reconcile Consolidated Segment Operating Margin to GAAP Gross margin, inclusive of depreciation and amortization. Consolidated Segment Operating Margin is mathematically equivalent to Revenue minus Cost of sales (excluding depreciation and amortization reflected separately) minus Operations and maintenance minus Vessel operating expenses, each as reported in our financial statements. We believe this non-GAAP measure, as we have defined it, offers a useful supplemental measure of the overall performance of our operating assets in evaluating our profitability in a manner that is consistent with metrics used for management's evaluation of the overall performance of our operating assets.
Consolidated Segment Operating Margin is not a measurement of financial performance under GAAP and should not be considered in isolation or as an alternative to Gross margin, income from operations, net income, cash flow from operating activities or any other measure of performance or liquidity derived in accordance with GAAP. As Consolidated Segment Operating Margin measures our financial performance based on operational factors that management can impact in the short-term, items beyond the control of management in the short term, such as depreciation and amortization are excluded. As a result, this supplemental metric affords management the ability to make decisions and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business.
The tables below present our segment information for the three months ended June 30, 2025 and March 31, 2025, and for the six months ended June 30, 2025 and June 30, 2024:
| Three Months Ended June 30, 2025 | |||||||||||||||||||||||||||||
| (in thousands of $) |
Terminals and Infrastructure |
Ships | Total Segment |
Consolidation and Other |
Consolidated | ||||||||||||||||||||||||
| Total revenues | $ | 263,236 | $ | 38,456 | $ | 301,692 | $ | - | $ | 301,692 | |||||||||||||||||||
|
Cost of sales(1)
|
208,852 | - | 208,852 | - | 208,852 | ||||||||||||||||||||||||
|
Vessel operating expenses(2)
|
1,765 | 6,291 | 8,056 | - | 8,056 | ||||||||||||||||||||||||
|
Operations and maintenance(2)
|
59,817 | - | 59,817 | - | 59,817 | ||||||||||||||||||||||||
| Segment Operating Margin | $ | (7,198) | $ | 32,165 | $ | 24,967 | $ | - | $ | 24,967 | |||||||||||||||||||
| Three Months Ended June 30, 2025 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | (27,903) | |||||||||
| Depreciation and amortization | 52,870 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 24,967 | |||||||||
| Three Months Ended March 31, 2025 | |||||||||||||||||||||||||||||
| (in thousands of $) |
Terminals and Infrastructure |
Ships | Total Segment |
Consolidation
and Other(2)
|
Consolidated | ||||||||||||||||||||||||
| Total revenues | $ | 431,927 | $ | 38,609 | $ | 470,536 | $ | - | $ | 470,536 | |||||||||||||||||||
|
Cost of sales(1)
|
302,377 | - | 302,377 | - | 302,377 | ||||||||||||||||||||||||
|
Vessel operating expenses(2)
|
- | 7,176 | 7,176 | - | 7,176 | ||||||||||||||||||||||||
|
Operations and maintenance(2)
|
54,957 | - | 54,957 | - | 54,957 | ||||||||||||||||||||||||
| Segment Operating Margin | $ | 74,593 | $ | 31,433 | $ | 106,026 | $ | - | $ | 106,026 | |||||||||||||||||||
| Three Months Ended March 31, 2025 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | 52,969 | |||||||||
| Depreciation and amortization | 53,057 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 106,026 | |||||||||
| Six Months Ended June 30, 2025 | |||||||||||||||||||||||||||||
| (in thousands of $) |
Terminals and Infrastructure |
Ships | Total Segment |
Consolidation and Other |
Consolidated | ||||||||||||||||||||||||
| Total revenues | $ | 695,163 | $ | 77,065 | $ | 772,228 | $ | - | $ | 772,228 | |||||||||||||||||||
|
Cost of sales(1)
|
511,229 | - | 511,229 | - | 511,229 | ||||||||||||||||||||||||
|
Vessel operating expenses(2)
|
1,765 | 13,467 | 15,232 | - | 15,232 | ||||||||||||||||||||||||
|
Operations and maintenance(2)
|
114,774 | - | 114,774 | - | 114,774 | ||||||||||||||||||||||||
| Segment Operating Margin | $ | 67,395 | $ | 63,598 | $ | 130,993 | $ | - | $ | 130,993 | |||||||||||||||||||
| Six Months Ended June 30, 2025 | |||||||||||
| (in thousands of $) | Consolidated | ||||||||||
| Gross margin (GAAP) | $ | 25,066 | |||||||||
| Depreciation and amortization | 105,927 | ||||||||||
| Consolidated Segment Operating Margin (Non-GAAP) | $ | 130,993 | |||||||||
| 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)
|
450,977 | - | 450,977 | - | 450,977 | ||||||||||||||||||||||||
|
Vessel operating expenses(2)
|
- | 16,899 | 16,899 | - | 16,899 | ||||||||||||||||||||||||
|
Operations and maintenance(2)
|
107,840 | - | 107,840 | - | 107,840 | ||||||||||||||||||||||||
|
Deferred earnings from contracted sales(3)
|
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 | ||||||
(1)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Condensed Consolidated Statements of Operations and Comprehensive (Loss) Income.
(2)Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP.
(3)Deferred earnings from contracted sales represent forward sales transactions that were contracted in the second quarter of 2024 and prepayment for these sales was received. Revenue has been recognized in the Condensed Consolidated Statements of Operations and Comprehensive (Loss) Incomeduring the third and fourth quarters of 2024.
Terminals and Infrastructure Segment
| Three Months Ended | |||||||||||||||||
| (in thousands of $) | June 30, 2025 | March 31, 2025 | Change | ||||||||||||||
| Total revenues | $ | 263,236 | $ | 431,927 | $ | (168,691) | |||||||||||
| Cost of sales (exclusive of depreciation and amortization) | 208,852 | 302,377 | (93,525) | ||||||||||||||
| Vessel operating expenses | 1,765 | - | 1,765 | ||||||||||||||
| Operations and maintenance | 59,817 | 54,957 | 4,860 | ||||||||||||||
| Segment Operating Margin | $ | (7,198) | $ | 74,593 | $ | (81,791) | |||||||||||
| Six Months Ended, | |||||||||||||||||
| (in thousands of $) | June 30, 2025 | June 30, 2024 | Change | ||||||||||||||
| Total revenues | $ | 695,163 | $ | 1,033,165 | $ | (338,002) | |||||||||||
| Cost of sales (exclusive of depreciation and amortization) | 511,229 | 450,977 | 60,252 | ||||||||||||||
| Vessel operating expenses | 1,765 | - | 1,765 | ||||||||||||||
| Operations and maintenance | 114,774 | 107,840 | 6,934 | ||||||||||||||
| Deferred earnings from contracted sales | - | 90,000 | (90,000) | ||||||||||||||
| Segment Operating Margin | $ | 67,395 | $ | 564,348 | $ | (496,953) | |||||||||||
Total revenue
Total revenue for the Terminals and Infrastructure Segment decreased by $168.7 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025, and total revenue for the Terminals and Infrastructure Segment decreased by $338.0 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024.
The decrease in revenue in the second quarter of 2025 when compared to the first quarter of 2025 was primarily attributable to lower cargo sales. The reduction in volumes delivered due to the sale of our Jamaica Business in May 2025 was partially offset by increase in volumes delivered at our San Juan Facility and La Paz Facility.
•We recognized $24.3 million of revenue from cargos sales for the three months ended June 30, 2025 as compared to $182.7 million for the three months ended March 31, 2025, as we were able to utilize all volumes under our supply contracts in our downstream terminal operations.
•We delivered 3.0 TBtu from our Montego Bay Facility and Old Harbour Facility prior to the sale of our Jamaica Business in May 2025, compared to 6.4 TBtu during the three months ended March 31, 2025. The volumes delivered to our customers from our San Juan Facility and La Paz Facility together increased from 7.4 TBtu in the first quarter of 2025 to 11.2 TBtu in the second quarter of 2025.
•The average Henry Hub index pricing used to invoice our downstream customers decreased by 6% for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025.
The decrease in revenue in the first half of 2025 when compared to the first half of 2024 was primarily attributable to the termination of the grid stabilization project in the first quarter of 2024 and the sale of our Jamaica Business in May 2025.
•For the six months ended June 30, 2025, volumes delivered to downstream customers were 28.0 TBtu as compared to 42.1 TBtu for the six months ended June 30, 2024.
•The higher volumes in the first half of 2024 were primarily attributable to additional sales in Puerto Rico from our grid stabilization project. Our customer terminated the grid stabilization project in the first quarter of 2024. Additionally, PREPA's San Juan Facility was undergoing repairs and maintenance in the first quarter of 2025, further decreasing volumes sold in Puerto Rico in the current year.
•We delivered 9.4 TBtu from our Montego Bay Facility and Old Harbour Facility for the six months ended June 30, 2025, compared to 13.3 TBtu during the six months ended June 30, 2024. The lower volumes during the first half of 2025 were primarily due to maintenance at these facilities during the first quarter and sale of the Jamaica Business in May 2025.
The decrease in revenue for the six months ended June 30, 2025 was partially offset by an increase due to the following:
•Revenue from cargos sales was $207.0 million for the six months ended June 30, 2025, as compared to $24.5 million for the six months ended June 30, 2024.
•The average Henry Hub index pricing used to invoice our downstream customers increased by 72% for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024.
•During the six months ended June 30, 2024, our subsidiary Genera, recognized $32.0 million of incentive fee
revenue from providing operations and maintenance services. The Company has not recognized any incentive fee
revenue for the six months ended June 30, 2025.
Cost of sales
Cost of sales includes the procurement of feed gas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. We source LNG and natural gas from third parties and our own liquefaction facilities, including our first Fast LNG unit which was placed into service in the fourth quarter of 2024. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our liquefaction facilities are also included in Cost of sales. 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 $93.5 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025, primarily driven by lower costs incurred for cargo sales.
•During the three months ended June 30, 2025, we incurred $15.7 million of cargo sales costs as compared to $103.8 million for the three months ended March 31, 2025.
•We delivered slightly higher volumes of LNG to our downstream customers of 14.2 TBtu in the second quarter of 2025, compared to 13.8 TBtu in the first quarter of 2025. The weighted average cost of gas purchased decreased from $9.57 per MMBtu for the three months ended March 31, 2025 to $8.84 per MMBtu for the three months ended June 30, 2025.
•Vessel costs decreased by $5.6 million during the three months ended June 30, 2025 compared to the three months ended March 31, 2025. The vessel costs were lower in the second quarter as charter for vessels related to our Jamaica Business were assigned to the buyer.
Cost of sales increased by $60.3 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024, which was attributable to the following:
•In the first half of 2025, we incurred $119.5 million of cargo sales costs, compared to $12.8 million incurred in the first half of 2024.
The increase in cargo sales costs were offset by the following:
•We delivered 33% lower volumes to our customers during the first half of 2025, principally due to the sale of our Jamaica Business and downtime for repairs and maintenance at our San Juan Facility. The cost of gas purchased decreased by $38.3 million from $251.5 million during the six months ended June 30, 2024 to $213.2 million during the three months ended June 30, 2025.
•We recognized lower payroll and other operating costs of $42.2 million to provide services under Genera's operations and maintenance contract for the six months ended June 30, 2025 compared to $47.6 million for the six months ended June 30, 2024; these costs are passed onto PREPA.
The weighted-average cost of our LNG inventory balance to be used in our operations as of June 30, 2025 and December 31, 2024was $9.35 per MMBtu and $6.90 per MMBtu, respectively.
Vessel operating expenses
Vessel operating expenses of $1.8 million incurred during the three and six months ended June 30, 2025 relate to direct costs such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees associated with operating a vessel. No such costs were incurred in this segment in 2024.
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 increased by $4.9 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. The increase was primarily attributable to maintenance, port and logistics and other costs incurred for operating our San Juan Facility, La Paz Facility and our Fast LNG unit. The increase was partially offset by a decrease in costs due to the sale of our Jamaica Business in May 2025.
Operations and maintenance increased by $6.9 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase is primarily due to costs incurred at our Fast LNG unit and the Santa Catarina Facility that were placed into service at the end of 2024. In the first quarter of 2024, our grid stabilization contract was terminated and assets related to the project were sold to PREPA, resulting in a reduction in costs incurred at our San Juan Facility.
Ships Segment
| Three Months Ended, | |||||||||||||||||
| (in thousands of $) | June 30, 2025 | March 31, 2025 | Change | ||||||||||||||
| Total revenues | $ | 38,456 | $ | 38,609 | $ | (153) | |||||||||||
| Vessel operating expenses | 6,291 | 7,176 | (885) | ||||||||||||||
| Segment Operating Margin | $ | 32,165 | $ | 31,433 | $ | 732 | |||||||||||
| Six Months Ended, | |||||||||||||||||
| (in thousands of $) | June 30, 2025 | June 30, 2024 | Change | ||||||||||||||
| Total revenues | $ | 77,065 | $ | 85,162 | $ | (8,097) | |||||||||||
| Vessel operating expenses | 13,467 | 16,899 | (3,432) | ||||||||||||||
| Segment Operating Margin | $ | 63,598 | $ | 68,263 | $ | (4,665) | |||||||||||
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, 2025, three vessels included in the Energos Formation Transaction were leased to customers under long-term arrangements and are included in this segment.
Total revenue
Total revenue for the Ships segment decreased $0.2 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. Total revenue for the Ships segment decreased by $8.1million for the six months ended June 30, 2025 as compared to the six 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. The third-party charter of the vessels Energos Winterand Energos Mariaended during the third and fourth quarter of 2024, respectively, and we are using the vessel at our terminal operations, resulting in a decrease in the vessel charter revenue.
Vessel operating expenses
Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, and management fees. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.
Vessel operating expenses decreased $0.9 millionfor the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. Vessel operating expenses decreased $3.4 million for the six months ended June 30, 2025 as compared to the six months ended June 30, 2024. As discussed above, the vessel operating costs were lower as the vesselsEnergos Winter andEnergos Maria have been utilized for our terminal operations.
Other operating results
| Three Months Ended, | Six Months Ended, | ||||||||||||||||||||||||||||||||||
| (in thousands of $) | June 30, 2025 | March 31, 2025 | Change | June 30, 2025 | June 30, 2024 | Change | |||||||||||||||||||||||||||||
| Selling, general and administrative | $ | 57,256 | $ | 59,271 | $ | (2,015) | $ | 116,527 | $ | 141,332 | $ | (24,805) | |||||||||||||||||||||||
| Transaction and integration costs | 75,384 | 11,931 | 63,453 | 87,315 | 3,131 | 84,184 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 52,870 | 53,057 | (187) | 105,927 | 87,904 | 18,023 | |||||||||||||||||||||||||||||
| Asset impairment expense | 117,312 | 246 | 117,066 | 117,558 | 4,272 | 113,286 | |||||||||||||||||||||||||||||
| Goodwill impairment expense | 582,172 | - | 582,172 | 582,172 | - | 582,172 | |||||||||||||||||||||||||||||
| (Gain) loss on sale | (472,699) | - | (472,699) | (472,699) | 77,140 | (549,839) | |||||||||||||||||||||||||||||
| Total operating expense | 412,295 | 124,505 | 287,790 | 536,800 | 313,779 | 223,021 | |||||||||||||||||||||||||||||
| Operating income (expense) | (387,328) | (18,479) | (368,849) | (405,807) | 228,832 | (634,639) | |||||||||||||||||||||||||||||
| Interest expense | 206,408 | 213,694 | (7,286) | 420,102 | 157,743 | 262,359 | |||||||||||||||||||||||||||||
| Other (income) expense, net | (56,262) | (63,937) | 7,675 | (120,199) | 66,466 | (186,665) | |||||||||||||||||||||||||||||
| Loss on extinguishment of debt, net | 20,320 | 467 | 19,853 | 20,787 | 9,754 | 11,033 | |||||||||||||||||||||||||||||
| Loss before income taxes | (557,794) | (168,703) | (389,091) | (726,497) | (5,131) | (721,366) | |||||||||||||||||||||||||||||
| Tax (benefit) provision | (967) | 28,670 | (29,637) | 27,703 | 25,059 | 2,644 | |||||||||||||||||||||||||||||
| Net loss | $ | (556,827) | $ | (197,373) | $ | (359,454) | $ | (754,200) | $ | (30,190) | $ | (724,010) | |||||||||||||||||||||||
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 decreased by $2.0 million for the three months ended June 30, 2025, compared to the three months ended March 31, 2025. The decrease was mostly driven by lower screening costs for our development projects and bad debt expense during the quarter ended June 30, 2025. The decrease was partially offset by higher share-based compensation expense in the quarter ended June 30, 2025. Due to forfeitures during the quarter ended March 31, 2025, we recognized a reversal of previously recorded share-based compensation expense which significantly lowered the expense for the first quarter.
Selling, general and administrative decreased by $24.8 million for thesix months ended June 30, 2025 as compared to the six months ended June 30, 2024. During the first half of 2024, we recognized an additional allowance for uncollectible
receivables of $11.6 million. The allowance reduces outstanding receivables for certain customers to reflect the amount that we expect to receive. No significant additional allowance was recognized during the six months ended June 30, 2025. Due to forfeitures during the first half of 2025, we recognized a reversal of previously recorded share-based compensation expense which significantly lowered the expense for the period. The decreases above were partially offset by higher screening costs incurred for our development projects during the first half of 2025.
Transaction and integration costs
The transaction and integration costs of $75.4 million during the three months ended June 30, 2025 primarily relate to the sale of the Jamaica Business that was completed in May 2025. We incurred $67.0 million of transaction costs directly attributable to the sale, which included fees for novating a vessel charter to the buyer and contingent fees due to our advisors. Other costs relate to legal fees and other third party costs incurred by the Company in connection with amendments to credit agreements.
The transaction and integration costs of $11.9 million during the three months ended March 31, 2025 primarily relate to legal fees and other third party costs incurred in connection with amendments to our credit agreements.
We did not incur significant transaction and integration costs for the six months ended June 30, 2024.
Depreciation and amortization
Depreciation and amortization decreased by $0.2 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025.
Depreciation and amortization expense increased by $18.0 million for thesix months ended June 30, 2025 as compared to the six months ended June 30, 2024. The increase in depreciation expense resulted from the Fast LNG project and the Santa Catarina Facility being placed into service in December 2024, and was partially offset by a reduction due to the sale of certain turbines and equipment to PREPA in the first half of 2024, and sale of Jamaica Business in May 2025.
Asset impairment expense
For the three months ended June 30, 2025, the impairment charge of $117.3 million principally relates to the Lakach deepwater project and the development project in Pennsylvania. We determined that it was not probable that we would pursue development of the Lakach deepwater project, and impaired the capitalized project costs. In addition, after testing the recoverability of the capitalized costs for the development project in Pennsylvania, we concluded that the asset group was not recoverable. Accordingly, we recognized an impairment charge to reduce the carrying value of the asset group to its estimated fair value. We did not recognize any significant impairment expense during the first quarter of 2025.
During the three and six months ended June 30, 2024, the impairment charge related to the sale of our Miami Facility.
Goodwill impairment expense
For the three months ended June 30, 2025, we recognized an impairment of goodwill of $582.2 million primarily as a result of (i) the significant increase in the weighted average cost of capital which reflected a higher company specific risk premium, and (ii) a reduction in forecasted cash flows following changes in customer revenue projections and the timing of completion of development projects.
(Gain) loss on sale
In May 2025, the Company completed the sale of its Jamaica Business to Excelerate Energy Limited Partnership ("EELP"), a subsidiary of Excelerate Energy, Inc. for cash consideration of $1,055.0 million, subject to certain purchase price adjustments. We recognized a gain of $472.7 million for the six months ended June 30, 2025 related to the sale.
During the six months ended June 30, 2024, the Company recognized a loss of $77.5 million from the sale of turbines and related equipment to the PREPA.
Interest expense
Interest expense decreased by $7.3 million for the three months ended June 30, 2025 as compared to the three months ended March 31, 2025. During the first quarter of 2025, we amended our Term Loan A Credit Agreement, which removed the unused commitment, and recognized interest expense of $18.1 million relating to origination, structuring and other fees, which were previously capitalized. The decrease in interest expense on the Term Loan A Credit Agreement was partially offset by lower interest capitalized of $62.5 million during the quarter ended June 30, 2025 compared to $74.1 million during the quarter ended March 31, 2025.
Interest expense increased by $262.4million for the six months ended June 30, 2025, as compared to the six months ended June 30, 2024. The increase was primarily due to an increase in total principal balance outstanding.The total principal balance on outstanding facilities was $9.2 billion as of June 30, 2025 as compared to total outstanding debt of $7.8 billion as of June 30, 2024. We also capitalized interest expense of $136.6million during the first half of 2025 compared to $215.0 million for the six months ended June 30, 2024, as the Fast LNG project and Santa Catarina Facility were placed into service towards the end of 2024.
Other (income) expense, net
Other (income) expense, net was $(56.3) million and $(63.9) million for the three months ended June 30, 2025 and March 31, 2025, respectively. Other (income) expense, net was $(120.2) million and $66.5 million for the six months ended June 30, 2025 and 2024, respectively.
The Other income recognized in the three months ended June 30, 2025 and March 31, 2025 was primarily due to foreign currency remeasurement gains, supported by the appreciation of the Brazilian real against the U.S. dollar. We earned interest income of $14.1 million and $14.3 million for the three months ended June 30, 2025 and March 31, 2025, respectively. We also recognized a gain contingency associated with our sale of Centrais Elétricas de Sergipe Participações S.A, or CELSEPAR in 2022 of $5.2 million upon settlement in the second quarter of 2025.
Other income recognized in the first half of 2025 was primarily comprised of foreign currency gain due to remeasurement of U.S. dollar denominated debt in our Brazil subsidiary. The Company also recognized interest income of $28.4 million and $10.0 million during the six months ended June 30, 2025 and June 30, 2024.
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, net
During the three months ended June 30, 2025, we reduced the available capacity under our Revolving Facility by $270.0 millionand recognized $10.6 millionof loss on extinguishment of debt representing the write-off of unamortized deferred financing costs. We also recognized $5.9 million of loss on extinguishment of debt related to the repayment of the South Power Bonds in conjunction with closing of the sale of our Jamaica Business. Additionally, we made a partial repayment of the Term Loan A using proceeds from the sale and incurred a partial extinguishment loss of $3.8 million.
During the six months ended June 30, 2024, werecognized prepayment premium and unamortized financing costs of $7.9 million in connectionwith 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.
Tax provision
We recognized a tax benefit for the three months ended June 30, 2025 of $(1.0) million compared to a tax provision of $28.7 million for the three months ended March 31, 2025. Our tax provision was $27.7 million and $25.1 million for the six months ended June 30, 2025 and 2024, respectively. The tax provision recognized in the first half of 2025 was primarily driven by estimated taxes due on the gain from sale of the Jamaica Business, inclusion of foreign earnings related to our Puerto Rico and Brazil operations, and a valuation allowance of $11.0 million in our U.S. and foreign operations included in our effective tax rate.
Factors Impacting Comparability of Our Financial Results
Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:
•Our historical results of operations include our Jamaica Business. In May 2025, we completed the sale of our Jamaica Business, and we no longer include the results of operations of the Montego Bay Facility and Old Harbour Facility in our financial statements.
•Our future results of operations will include the cost of operating our Fast LNG solution that were not included in our historical financial statements. We placed our first Fast LNG project into service in the fourth quarter of 2024. This project represents our largest ever capital project and placing the asset into service will significantly increase the depreciation recognized in future periods; such depreciation will also impact the cost of LNG delivered from the FLNG facility. We also expect interest expense to increase as we are no longer able to capitalize borrowing costs associated with this development.
While the asset is in service, we continue to optimize the asset to enhance liquefaction capacity. Such costs that enhance the asset are capitalized on our Condensed Consolidated Balance Sheets.
•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 months ended June 30, 2025include our San Juan Facility, La Paz Power Plant and certain industrial end-users. We placed the Santa Catarina Facility into service in the fourth quarter of 2024. We have also completed construction of our Barcarena Facility and are in the final stages of commissioning this facility. 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.
In the first quarter of 2024, our grid stabilization contract was terminated and related assets were sold to PREPA. We continued to supply gas to these power generation assets under an island-wide gas sales agreement with PREPA, which initially expired in March 2025. During 2025, the Company and PREPA agreed to a series of short-term extensions of the gas supply agreement while working towards a long-term solution that is in the best interests of both parties and achieves our mutual goal of sustained, efficient power generation for Puerto Rico. The gas supply agreement is currently set to expire on September 12, 2025. There can be no assurances that the long-term gas sale agreement will be executed, and to the extent the Company is not able to execute such an agreement, the Company's future results of operations could be adversely impacted and the impact could be material.
Liquidity and Capital Resources
As part of preparing the condensed consolidated financial statements included in this Quarterly Report, we have evaluated whether conditions exist that give rise to substantial doubt as to the ability of the Company to continue as a going concern, considering the following:
•In the first and second quarters of 2025, we recognized operating losses and negative operating cash flows, and this decline in earnings accelerated in the second quarter of 2025. Our forecasted cash flows are expected to be impacted by, among other things, (i) reduced earnings following the sale of the Jamaica Business, (ii) increased interest expense, and (iii) cash tax payments resulting from the taxable gain on the sale of the Jamaica Business in May 2025.
•We were required to provide a $79,100 bank guarantee to holders of the PortoCem Debentures on or before August 17, 2025; this guarantee was not provided by the deadline, and as a result, a majority of debenture holders have the right to call for a meeting of holders and declare an event of early maturity. If the debenture holders exercise their right to declare an early maturity, substantially all of the Company's outstanding indebtedness would be payable on demand.
•As of the date of this filing, we do not expect to be in compliance with the consolidated first lien ratio or the fixed charge coverage ratio included within the Revolving Facility, Letter of Credit Facility and Term Loan A Credit Agreement for the fiscal quarter ending September 30, 2025. If we are not in compliance with these covenants and this non-compliance is not waived, the lenders have the right to accelerate the repayment of the outstanding
principal under the Revolving Facility and Term Loan A and require cash collateralization of all outstanding letters of credit. If lenders choose to accelerate under those facilities, substantially all of our outstanding indebtedness would be payable on demand. If substantially all of our outstanding indebtedness is accelerated, we would not have the sufficient liquidity or capital resources to satisfy the outstanding principal obligations.
•Additionally, we have $510.9 million aggregate principal amount outstanding as of June 30, 2025 under our 2026 Notes, which mature on September 30, 2026. If more than $100 million of the 2026 Notes remain outstanding 91 days prior to this maturity date (the "Springing Maturity Date"), the outstanding principal of $2.7 billion under the New 2029 Notes becomes due. If any of the 2026 Notes remains outstanding on the Springing Maturity Date, the outstanding balance under the Revolving Facility becomes due. As of June 30, 2025, the Revolving Facility was fully drawn with $710.4 million in revolving loans and $19.5 million in letters of credit. Additionally, if any of the 2026 Notes remain outstanding on July 31, 2026, the outstanding principal under the Term Loan B becomes due. Also, if any of the 2026 Notes remain outstanding 60 days prior to the maturity date of the 2026 Notes, the outstanding principal under the Term Loan A becomes due. As of June 30, 2025, there was $295.0 million outstanding under the Term Loan A and $1.27 billion outstanding under the Term Loan B.
As such, management has concluded that our current liquidity and forecasted cash flows from operations are not probable to be sufficient to support, in full, its obligations as they become due, and there is substantial doubt as to the Company's ability to continue as a going concern.
We are currently engaged in discussions with holders of the PortoCem Debentures to obtain a waiver of the debenture holders' ability to declare an event of early maturity. Should we not be in compliance with covenants in the Revolving Facility, Letter of Credit Facility and Term Loan A, we will engage in negotiations with these lenders to obtain a waiver to avoid acceleration of outstanding balances. We have also initiated a process to evaluate strategic alternatives and have retained a financial advisor to assist in this evaluation. We, along with our advisors, are considering all options available, including asset sales, capital raising, debt amendments and refinancing transactions, and other strategic transactions that seek to provide additional liquidity and relief from acceleration under its debt agreements. There are inherent uncertainties as the outcome of these negotiations and potential transactions described above are outside management's control, and therefore there are no assurances that management will be successful in these negotiations and that any of these potential transactions will occur. In addition, there can be no assurances that these transactions will sufficiently improve our liquidity or that we will otherwise realize the anticipated benefits.
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 the Refinancing Transactions in the fourth quarter of 2024, our ability to undertake these activities, including our ability to incur or refinance our debt, is further limited. Furthermore, the restrictions imposed by certain of the amendments to our Revolving Facility 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.
We are also evaluating strategies to obtain the required additional funding for our future operations, including the following transactions that are excluded from our forecast, among other things: (1) settlement of our claims resulting from the termination of the emergency power services contract in Puerto Rico in the first quarter of 2024, (2) realization of up to $110.0 million in proceeds from the modification of Genera's Operation and Maintenance Agreement; (3) receipt of proceeds from the sale of the Jamaica Business that are currently in escrow of approximately $98.6 million; and (4) expected cash flows from new business in Puerto Rico and Brazil.
Our remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, is approximately $467 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 Barcarena Power Plant and PortoCem Power Plant, which represents approximately $196 million of our upcoming committed capital expenditures.
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 potential future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.
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, 2025:
| (in thousands of $) | Total | Less than Year 1 | Years 2 to 3 | Year 4 to 5 |
More than 5 years |
||||||||||||||||||||||||
| Long-term debt obligations | $ | 14,134,152 | $ | 560,089 | $ | 3,584,894 | $ | 6,267,052 | $ | 3,722,117 | |||||||||||||||||||
| Purchase obligations | 16,938,768 | 351,093 | 505,202 | 1,143,193 | 14,939,280 | ||||||||||||||||||||||||
| Lease obligations | 597,586 | 71,906 | 179,134 | 149,690 | 196,856 | ||||||||||||||||||||||||
| Total | $ | 31,670,506 | $ | 983,088 | $ | 4,269,230 | $ | 7,559,935 | $ | 18,858,253 | |||||||||||||||||||
Long-term debt obligations
For information on our long-term debt obligations, see "-Liquidity and Capital Resources-Long-Term Debt" in our Annual Report.The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of June 30, 2025.
A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above.
Purchase obligations
We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are basedon the spot price of that index as of June 30, 2025.
We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena 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 six months ended June 30, 2025 and 2024, respectively:
| Six Months Ended June 30, | |||||||||||||||||
| (in thousands of $) | 2025 | 2024 | Change | ||||||||||||||
| Cash flows from: | |||||||||||||||||
| Operating activities | $ | (384,156) | $ | 162,968 | $ | (547,124) | |||||||||||
| Investing activities | 301,449 | (882,715) | 1,184,164 | ||||||||||||||
| Financing activities | (110,428) | 735,679 | (846,107) | ||||||||||||||
| Net (decrease) increase in cash, cash equivalents, and restricted cash | $ | (193,135) | $ | 15,932 | $ | (209,067) | |||||||||||
Cash (used in) / provided by operating activities
Our cash flow used in operating activities was $384.2 million for the six months ended June 30, 2025, which decreased by $547.1 million from cash provided by operating activities of $163.0 million for the six months ended June 30, 2024. Our net loss for the six months ended June 30, 2025, when adjusted for non-cash items, increased by $520.0 million from the six months ended June 30, 2024. Non-cash items during the six months ended June 30, 2025 included goodwill impairment expense of $582.2 million, and asset impairment expense of $117,558 million related to the Lakach deepwater project and the development project in Pennsylvania. We also recognized a gain on sale of $472.7 million related to the sale of the Jamaica Business.
Cash provided by / (used in) investing activities
Our cash flow used in investing activities was $301.4 million for the six months ended June 30, 2025, which increased by $1,184.2 million from cash used in investing activities of $882.7 million for the six months ended June 30, 2024. Cash flows from investing activities during the six months ended June 30, 2025 were primarily from proceeds of $949.5 million from the sale of the Jamaica Business. Cash inflows were offset by cash outflows for continued construction of the PortoCem Power Plant.
Cash outflows for investing activities during the six months ended June 30, 2024 were used primarily for the continued development of our Fast LNG project and the construction of the PortcoCem 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 (used in) / provided by financing activities
Our cash flow used in financing activities was $110.4 million for the six months ended June 30, 2025, which increased by $846.1 million from cash provided by financing activities of $735.7 million for the six months ended June 30, 2024. During the six months ended June 30, 2025 we had total borrowings of $1.3 billion, a portion of which were used to repay the Barcarena Debentures in full. We also repaid our Revolving Facility and repaid our short-term borrowings under repurchase agreements, prior to drawing on these facilities. In conjunction with closing the sale of the Jamaica Business, we repurchased all outstanding South Power Bonds for $227.1 million.
In the first half 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. We also 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.
Long-Term Debt
The terms of our debt instruments and associated obligations have been described in our Annual Report. There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below.
Revolving Facility
In May 2025, we entered into an amendment to the Revolving Facility to, among other things, (i) provide for a covenant holiday with respect to the consolidated first lien debt ratio and fixed charge coverage ratio contained therein for the fiscal quarter ending June 30, 2025, (ii) permit $270.0 million of proceeds from the sale of the Jamaica Business to be used to prepay and terminate a portion of loans and commitments currently outstanding and otherwise not require the proceeds of the sale of the Jamaica Business to be used to prepay loans and commitments, (iii) provide that the asset sale sweep mandatory prepayment will no longer apply once aggregate commitments are reduced to $550.0 million and (iv) restrict the Company from prepaying the 2026 Notes in excess of $200.0 million other than to avoid springing maturities unless any such prepayment is made using proceeds from refinancing indebtedness or capital contributions.
InMay 2025, we repaid $270.0 millionof outstanding balance under the Revolving Facility which permanently reduced the borrowing capacity to $730.0 million. Additionally, we have issued letters of credit of $19.5 millionin the second quarter of 2025, and including the outstanding letters of credit, we have fully utilized the borrowing capacity of $729.9 million as of June 30, 2025.
The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.
We do not expect to be in compliance with the consolidated first lien debt ratio or the fixed charge coverage ratio in the Revolving Facility for the fiscal quarter ending September 30, 2025. If we are not compliance with both of these covenants and this non-compliance is not waived, the lenders have the right to accelerate the repayment of all outstanding balances under the Revolving Facility. At this point, substantially all of our outstanding indebtedness would be payable on demand.
Term Loan B Credit Agreement
In March 2025, we entered into an amendment to the Term Loan B Credit Agreement. Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425.0 million, which increased the total outstanding principal amount to $1,272.4 million ("Term Loan B"). The incremental term loans were issued at a discount, and we received proceeds, net of discount, of $391.0 million. Net proceeds will be used primarily to fund capital expenditures of the onshore FLNG project, and for other corporate expenses. The incremental term loans are subject to the same maturity date as the term loans under the original agreement. Quarterly principal payments of approximately $3.2 million are required beginning June 2025.
The Term Loan B is secured by the same collateral as that secured the term loans under the original agreement. The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the amendment) plus 5.5%. We may prepay the Term Loan B at its option subject to prepayment premiums until March 10, 2028 and customary break funding costs. We are required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances and with our Excess Cash Flow (as defined in the amendment), in each case
subject to certain exceptions and thresholds. We must comply with the same covenant requirements as those under the original agreement.
The Term Loan B Credit Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B Credit Agreement.
Term Loan A Credit Agreement
In March 2025, we entered into an amendment to the Term Loan A Credit Agreement. Pursuant to the amendment, the future borrowing commitments are reduced to zero, eliminating the potential for future borrowings under the Term Loan A Credit Agreement.
In May 2025, we entered into an additional amendment to the Term Loan A Credit Agreement to, among other things, (i) require $55.0 million of proceeds from the sale of the Jamaica Business to be used to prepay a portion of loans currently outstanding; (ii) increase the applicable margin to 6.70% for SOFR loans and 5.70% for Base Rate Loans and implement a Term SOFR floor of 4.30% for initial term loans and a base rate minimum of 5.30%; (iii) require us to make mandatory prepayments with 12.5% of proceeds of a $659.0 million request for equitable adjustment and any other proceeds related to the early termination of contracts associated with the grid stabilization project in Puerto Rico, if and when such proceeds are received. Additionally, this amendment amends certain of the financial covenants, whereby the consolidated first lien debt ratio cannot exceed (i) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (ii) 6.50 to 1.00, for the fiscal quarter ending December 31, 2025, (iii) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 and September 30, 2026 and (iv) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter. The amendment added a fixed charge coverage ratio covenant and removed the debt to total capitalization covenant. We cannot permit the fixed charge coverage ratio for us and our restricted subsidiaries to be less than or equal to 1.00 to 1.00 for the fiscal quarter ending September 30, 2025 and each fiscal quarter thereafter. The first lien debt ratio and the fixed charge coverage ratio covenants were waived for the fiscal quarter ended June 30, 2025.
We do not expect to be in compliance with the consolidated first lien debt ratio or the fixed charge coverage ratio for the fiscal quarter ending September 30, 2025. If we are not compliance with both of these covenants and this non-compliance is not waived, the lenders have the right to accelerate the repayment of the remaining outstanding principal under the Term Loan A. At this point, substantially all of the Company's outstanding indebtedness would be payable on demand.
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 consistent with those under the Revolving Facility, including Debt to EBITDA Ratio and minimum consolidated liquidity.
Brazil Financing Notes
In February 2025, one of our consolidated subsidiaries entered into an agreement to issue up to $350.0 million aggregate principal amount of 15.0%Senior Secured Notes due 2029 (the "Brazil Financing Notes") at a purchase price of 97.75%of par. The Brazil Financing Notes mature on August 30, 2029; the principal is due in full on the maturity date. Interest is payable quarterly in arrears beginning on June 30, 2025, and for the first 30 months that the Brazil Financing Notes are outstanding, interest due can be paid in kind and added to the principal amount. A portion of the proceeds from the issuance of the Brazil Financing Notes of $208.7 million was used to repay the Barcarena Debentures in full.
The Brazil Financing Notes contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Brazil Financing Notes.
PortoCem Debentures
The PortoCem Debentures included a non-automatic early maturity provision whereby upon multiple downgrades of the Company's credit rating, early maturity may be declared if approved by the majority of debenture holders. Prior to the
issuance of these financial statements, our credit ratings were downgraded, triggering the right of the debenture holders to determine if an early maturity event should be declared. On May 23, 2025, the debenture holders unanimously permanently waived their ability to declare an early maturity event due to this credit ratings downgrade. In connection with the debenture holders' decision to not declare an early maturity event, we agreed to provide a bank guarantee of $129.1 million prior to August 17, 2025.
On June 5, 2025, we received an additional downgrade of our credit rating, which triggered an non-automatic event of early maturity under the PortoCem Debenture. On June 26, 2025, the debenture holders unanimously permanently waived their ability to declare an early maturity event due to this credit ratings downgrade. No additional collateral was required; however, we were required to provide $50.0 million of the previously required bank guarantee on or before July 7, 2025. The remaining $79.1 million bank guarantee is due prior to August 17, 2025. Additionally, the debenture holders agreed to amend the debenture agreement to suspend the provision that allows for a non-automatic early maturity event upon certain downgrades of our credit rating through August 30, 2026.
We provided the required $50.0 millionbank guarantee on July 9, 2025, subsequent to the required deadline of July 7, 2025. On August 7, 2025 the debenture holders unanimously waived their ability to declare an early maturity event due to the failure to timely meet this condition in the previous waiver. Additionally, the Company did not provide the required $79.1 millionbank guarantee prior to August 17, 2025, and is currently in discussions with the debenture holders to delay or eliminate this requirement. As the required $79.1 millionbank guarantee has not been delayed or eliminated and was not provided prior to August 17, 2025, a majority of debenture holders have the right to call for a meeting of holders and declare an event of early maturity. If the debenture holders exercise their right to declare an early maturity, substantially all of our outstanding indebtedness would be payable on demand.
The PortoCem Debentures contain usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The PortoCem Debentures do not contain any restrictive financial covenants.
South Power 2029 Bonds
OnMay 14, 2025, we completed the sale of the Jamaica Business. In conjunction with closing, we repurchasedall outstanding South Power Bonds for $227.2 million, including a 1.0%prepayment penalty and accrued interest.
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, 2025, 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.
New Fortress Energy Inc. published this content on September 05, 2025, and is solely responsible for the information contained herein. Distributed via SEC EDGAR on September 05, 2025 at 21:12 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]