nfe-20241231

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K


x			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the year ended December 31, 2024


o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to_______

Commission File Number: 001-38790

New Fortress Energy Inc.

(Exact Name of Registrant as Specified in its Charter)


Delaware			83-1482060
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)


111 W. 19th Street, 8th Floor New York, NY			10011
(Address of principal executive offices)			(Zip Code)

Registrant’s telephone number, including area code: (516) 268-7400

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class A common stock	NFE	Nasdaq Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer x			Accelerated filer o
Non-accelerated filer o			Smaller reporting company ☐
			Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed as of June 28, 2024 (the last business day of the registrant’s most recently completed second fiscal quarter), based on the closing price of the Class A common stock on the Nasdaq Global Select Market, was $2,274.6 million.

At February 28, 2025, the registrant had 273,771,811 shares of Class A common stock outstanding.

Documents Incorporated by Reference:

Portions of the registrant’s definitive proxy statement for the registrant’s 2025 annual meeting, to be filed within 120 days after the close of the registrant’s fiscal year, are incorporated by reference into Part III of this Annual Report on Form 10-K.

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GLOSSARY OF TERMS			1
CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS			2
PART I			4
	Items 1 and 2.	Business and Properties	4
	Item 1A.	Risk Factors	18
	Item 1B.	Unresolved Staff Comments.	55
	Item 1C.	Cybersecurity	55
	Item 3.	Legal Proceedings.	56
	Item 4.	Mine Safety Disclosures.	56
PART II			57
	Item 5.	Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.	57
	Item 6.	[Reserved.]	58
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	59
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	87
	Item 8.	Financial Statements and Supplementary Data.	88
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	88
	Item 9A.	Controls and Procedures.	88
	Item 9B.	Other Information.	89
	Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.	89
PART III			90
	Item 10.	Directors, Executive Officers and Corporate Governance.	90
	Item 11.	Executive Compensation	90
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	90
	Item 13.	Certain Relationships and Related Transactions, and Director Independence.	90
	Item 14.	Principal Accountant Fees and Services.	90
PART IV			91
	Item 15.	Exhibits, Financial Statement Schedules.	91
	Item 16.	Form 10-K Summary	98
SIGNATURES			99

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GLOSSARY OF TERMS

As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this Annual Report on Form 10-K (“Annual Report”), the terms listed below have the following meanings:


ADO			automotive diesel oil

Bcf/yr			billion cubic feet per year

Btu			the amount of heat required to raise the temperature of one avoirdupois pound of pure water from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an absolute pressure of 14.696 pounds per square inch gage

CAA			Clean Air Act

CERCLA			Comprehensive Environmental Response, Compensation and Liability Act

CWA			Clean Water Act

DOE			U.S. Department of Energy

DOT			U.S. Department of Transportation

EPA			U.S. Environmental Protection Agency

FTA countries			countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas

GAAP			generally accepted accounting principles in the United States

GHG			greenhouse gases

GSA			gas sales agreement

Henry Hub			a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange

ISO container			International Organization of Standardization, an intermodal container

LNG			natural gas in its liquid state at or below its boiling point at or near atmospheric pressure

MMBtu			one million Btus, which corresponds to approximately 12.1 gallons of LNG

mtpa			metric tons per year

MW			megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt.

NGA			Natural Gas Act of 1938, as amended

non-FTA countries			countries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted

OPA			Oil Pollution Act

OUR			Office of Utilities Regulation (Jamaica)

PHMSA			Pipeline and Hazardous Materials Safety Administration

PPA			power purchase agreement

SSA			steam supply agreement

TBtu			one trillion Btus, which corresponds to approximately 12,100,000 gallons of LNG

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CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K for the year ended December 31, 2024 (this “Annual Report”) contains forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this Annual Report other than historical information are forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance or our projected business results. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “projects,” “targets,” “potential” or “continue” or the negative of these terms or other comparable terminology. Such forward-looking statements are necessarily 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. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:

•adequately addressing the substantial doubt as to our ability to continue as a going concern and satisfy our liquidity needs, including the consummation of our refinancing transactions intended to extend our debt maturities and enhance our liquidity;

•the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest and their ability to make dividends or distributions to us;

•construction and operational risks related to our facilities and assets, including cost overruns and delays;

•failure of LNG or natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;

•complex regulatory and legal environments related to our business, assets and operations, including actions by governmental entities or changes to regulation or legislation, in particular related to our permits, approvals and authorizations for the construction and operation of our facilities;

•delays or failure to obtain and maintain approvals and permits from governmental and regulatory agencies;

•failure to obtain a return on our investments for the development of our projects and assets and the implementation of our business strategy;

•failure to maintain sufficient working capital for the development and operation of our business and assets;

•failure to convert our customer pipeline into actual sales;

•lack of asset, geographic or customer diversification, including loss of one or more of our customers;

•competition from third parties in our business;

•cyclical or other changes in the demand for and price of LNG and natural gas;

•inability to procure LNG at necessary quantities or at favorable prices to meet customer demand, or otherwise to manage LNG supply and price risks, including hedging arrangements;

•inability to successfully develop and implement our technological solutions;

•inability to service our debt and comply with our covenant restrictions;

•inability to obtain additional financing to effect our strategy;

•inability to successfully complete mergers, sales, divestments or similar transactions related to our businesses or assets or to integrate such businesses or assets and realize the anticipated benefits;

•economic, political, social and other risks related to the jurisdictions in which we do, or seek to do, business;

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•weather events or other natural or manmade disasters or phenomena;

•any future pandemic or any other major health and safety incident;

•increased labor costs, disputes or strikes, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;

•the tax treatment of, or changes in tax laws applicable to, us or our business or of an investment in our Class A common stock; and

•other risks described in the “Risk Factors” section of this Annual Report.

All forward-looking statements speak only as of the date of this Annual Report. When considering forward-looking statements, you should keep in mind the risks set forth under “Item 1A. Risk Factors” and other cautionary statements included in this Annual Report. The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We undertake no duty to update these forward-looking statements, even though our situation may change in the future. Furthermore, we cannot guarantee future results, events, levels of activity, performance, projections or achievements.

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PART I

Items 1 and 2. Business and Properties

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 below under “Sustainability—Toward a Very-Low Carbon Future.”

We deliver targeted energy solutions by employing an integrated LNG supply and delivery model:

LNG and Natural Gas Supply and Liquefaction – We supply LNG and natural gas to our own power plants and to our customers. We typically supply LNG and natural gas regasified from LNG to our customers by entering into long-term supply contracts, which are generally based on an index such as Henry Hub plus a fixed fee component. We acquire our LNG from third party suppliers in open market purchases and long-term supply agreements. Our first floating liquefaction unit, which we refer to as "Fast LNG" or "FLNG", began producing LNG in July 2024, and we plan to source a portion of our LNG needs from this facility.

Shipping – We lease, own or operate a fleet of seven regasification units (“FSRUs”) and 12 liquefied natural gas carriers (“LNGCs”) and floating storage units (“FSUs”). Ten vessels are owned by Energos Infrastructure ("Energos"). We also charter vessels to and from third parties as well as from Energos.

Facilities – Through our network of current and planned downstream facilities and logistics assets, we are strategically positioned to deliver gas and power solutions to our customers seeking either to transition from environmentally dirtier distillate fuels such as automotive diesel oil (“ADO”) and heavy fuel oil (“HFO”) or to purchase natural gas to meet their current fuel needs.

Our Business Model

As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to shipping, logistics, facilities and conversion or development of natural gas-fired power generation. Historically, natural gas procurement or liquefaction, transportation, regasification and power generation projects have been developed separately and have required multilateral or traditional financing sources, which has inhibited the introduction of natural gas-fired power in many developing countries. In executing our business model, we have the capability to build or arrange any necessary infrastructure ourselves without reliance on multilateral financing sources or traditional project finance structures, so that we maintain our strategic flexibility and optimize our portfolio.

We currently conduct our operations at the following facilities:

•our LNG storage and regasification facility at the Port of Montego Bay, Jamaica (the “Montego Bay Facility”),

•our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility”, together with the Montego Bay Facility, the “Jamaica Facilities”),

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•our dual-fired combined heat and power ("CHP") facility in Clarendon, Jamaica (the "CHP Plant"),

•our landed micro-fuel handling facility in San Juan, Puerto Rico (the “San Juan Facility”)

•our LNG receiving facility (the “La Paz Facility”) and gas-fired power plant (the "La Paz Power Plant") at the Port of Pichilingue in Baja California Sur, Mexico, and

•our LNG receiving facility located on the southern coast of Brazil (the “Santa Catarina Facility” ).

In addition, we are currently developing facilities in Brazil, Nicaragua, Ireland and other locations, as described below in more detail. We are in active discussions with additional customers to develop projects in multiple regions around the world who 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 pricing or margins.

Our Facilities

We look to build facilities in locations where the need for natural gas is significant. We design and construct natural gas and power facilities to meet the supply and demand specifications of our current and potential future customers in an applicable region. In these markets, we first seek to identify and establish “beachhead” target markets for the sale of LNG, natural gas or natural gas-fired power, and we then seek to supply natural gas or power under long-term downstream contracts. Finally, our goal is to expand within the market and supply natural gas or power to additional industrial and transportation customers.

Our facilities position us to acquire and supply LNG to customers and natural gas-fired power in a number of attractive markets around the world. Downstream, we have 14 facilities that are either operational or under active development. We currently have five operational LNG terminal facilities and three under active development, as well as two operational power plant facilities and four power plant facilities under active development, as described below. Our LNG facilities currently operating or under development are expected to be capable of receiving up to one million MMBtu from LNG per day depending upon the needs of our customers and potential demand in the region.

Set forth below is additional detail regarding each of our LNG and power facilities:

Montego Bay, Jamaica – Our Montego Bay Facility commenced commercial operations in October 2016. The Montego Bay Facility is capable of processing up to 60,000 MMBtu from LNG per day and features approximately 7,000 cubic meters of onsite storage. It supplies natural gas to the 145MW power plant (the “Bogue Power Plant”) operated by Jamaica Public Service Company Limited (“JPS”) pursuant to a long-term contract for natural gas equivalent to approximately 25,000 MMBtu from LNG per day. The Montego Bay Facility also supplies numerous on-island industrial users with natural gas or LNG pursuant to offtake contracts of various durations. We have total aggregate contracted volumes of approximately 29,000 MMBtu from LNG per day at our Montego Bay Facility with a weighted average remaining contract length of 15 years as of December 31, 2024. We have the ability to service other potential customers with the excess capacity of the Montego Bay Facility, and we are seeking to enter into long-term contracts with new customers for such purposes.

Old Harbour, Jamaica – Our Old Harbour Facility commenced commercial operations in June 2019. The Old Harbour Facility is an offshore facility with storage and regasification equipment provided via FSRU. The offshore design eliminates the need for onshore infrastructure and storage tanks. It is capable of processing up to 750,000 MMBtu from LNG per day. The Old Harbour Facility is supplying gas to a 190MW gas-fired power plant (the “Old Harbour Power Plant”) owned and operated by South Jamaica Power Company Limited (“SJPC”) pursuant to a long-term contract for natural gas equivalent to approximately 30,000 MMBtu from LNG per day, and back-up ADO, for 20 years.

The Old Harbour Facility is also supplying gas to our 100MW CHP Plant, which we constructed, and which commenced commercial operations in March 2020. The CHP Plant is fueled by natural gas, with the ability to run on ADO as a backup fuel source. We have executed a suite of agreements in connection with the CHP Plant, including a 20-year agreement to supply steam to an alumina refinery joint venture between affiliates of Century Aluminum Company, and the Government of Jamaica, and we have a 20-year agreement to supply electricity to JPS.

We have total aggregate contracted volumes of approximately 58,000 MMBtu from LNG per day at our Old Harbour Facility with a weighted average contract length of 15 years as of December 31, 2024. We have the ability to service other

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potential customers with the excess capacity of the Old Harbour Facility, and we are seeking to enter into long-term contracts with new customers for such purposes.

San Juan, Puerto Rico – Our San Juan Facility became fully operational in July 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 Puerto Rico Electric Power Authority ("PREPA") San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico.

In 2023, we entered into agreements for the installation and operation of approximately 350MW of 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 and ADO. 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. 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 to PREPA. The contract initially has a one year term that is renewable annually for three additional annual periods.

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 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 improving reliability of power generation in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees, beginning after the service period under the contract commenced on July 1, 2023.

La Paz, Baja California Sur, Mexico – Our La Paz Facility commenced operations in the fourth quarter of 2021. It is an LNG receiving facility located at the Port of Pichilingue in Baja California Sur, Mexico, receiving LNG via ISO containers on an offshore supply vehicle from a nearby vessel. Beginning in 2021, we have entered into a gas sales agreements with CFEnergia ("CFE"), a subsidiary of Federal Electricity Commission (Comisión Federal de Electricidad), Mexico’s power utility, for the supply of natural gas to power plants located at Punta Prieta and Coromuel in the State of Baja California Sur ("CFE Plants"), We continue to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur, and in the third quarter of 2024, we executed a 10-year gas sales agreement to supply natural gas to additional CFE facilities on take-or-pay basis.

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. We expect to sell approximately 38,000 MMBtu from LNG per day to CFE and for use in the La Paz Power Plant.

Santa Catarina, Brazil – 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 Sao Paulo, within the city limits of Lins, Brazil. We expect to participate in upcoming power auctions in Brazil scheduled for June 2025, and to the extent that we are successful in these auctions, we expect to develop a gas-fired power plant using natural gas from the Santa Catarina Facility.

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Barcarena, Brazil – Our LNG receiving facility located in the State of Pará, Brazil (the Barcarena Facility" and, together with the Santa Catarina Facility, the "Brazil Facilities") consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of delivering almost 600,000 MMBtu from LNG per day and storing up to 160,000 cubic meters of LNG. We have entered into a 15-year gas supply agreement with a subsidiary of Norsk Hydro ASA for the supply of natural gas to the Alunorte Alumina Refinery in Pará, Brazil, through our Barcarena Facility. We have substantially completed our Barcarena Facility and are in process of final commissioning.

The Barcarena Facility will also supply our new 630MW combined cycle natural gas-fired 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. Construction of the Barcarena Power Plant was greater than 88% complete as of December 31, 2024. 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") 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 transferred the 1.6 GW capacity reserve contract to a site owned by NFE that is adjacent to the Barcarena Facility, where NFE is building the 1.6 GW simple cycle, natural gas-fired power plant (the "PortoCem Power Plant") to supply the capacity reserve contract using gas from the Barcarena Facility. Construction of the PortoCem Power Plant was greater than 39% complete as of December 31, 2024, and we expect the PortoCem Power Plant to be complete in 2026.

Puerto Sandino, Nicaragua – We are developing an offshore liquefied natural gas receiving, transloading and regasification facility off the coast of Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”). The Puerto Sandino Facility is expected to supply gas via a pipeline to our new approximately 300MW natural gas-fired power plant in Puerto Sandino, Nicaragua (the “Nicaragua Power Plant”) that we will own and operate. We have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies. 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.

Shannon, Ireland – We intend to develop and operate an LNG facility (the “Ireland Facility” and, together with the Jamaica Facilities, the San Juan Facility, the Brazil Facilities, the La Paz Facility and the Puerto Sandino Facility, our “LNG Facilities”) and a power plant on the Shannon Estuary, near Tarbert, Ireland (the “Ireland Power Plant” and, together with the CHP Plant, La Paz Power Plant, Nicaragua Power Plant, Barcarena Power Plant and PortoCem Power Plant, the “Power Plants,” and together with the LNG Facilities, the “Facilities”). In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We challenged this decision, and in September 2024, the High Court of Ireland ruled that the ABP did not have appropriate grounds for the denial of our permit. The ABP has been directed to reconsider our permit application in accordance with Irish law. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations.

ZeroParks – In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies.

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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 our Beaumont Facility to be the largest green hydrogen plant in the United States.

Klondike – In July 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.

LNG Supply

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 TBtus 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 Montego Bay Facility, Old Harbour Facility, 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.

Liquefaction Assets

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 first “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) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

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.

Our first Fast LNG unit has been deployed 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 placed the asset into service for accounting purposes in the fourth quarter of 2024. While the asset is in service from an accounting perspective, we continue to finalize commissioning, and we expect to achieve run rate production in 2025.

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We expect to deploy up to two 1.4MTPA additional FLNG units onshore at the existing Altamira LNG import facility. The terminal would also 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.

Our Shipping Assets

Our shipping assets include: FSRUs, FSUs and LNGCs, which are either leased to customers under long-term or spot arrangements or commercially operated by us. FSRUs provide offshore storage and regasification capabilities and are generally less costly and substantially faster to deploy compared to the construction and development of land-based LNG regasification and storage facilities. FSUs are floating storage assets, which often provide storage for LNG but are also capable of transporting LNG when required. LNGC's are vessels that transport LNG and are compatible with many LNG loading and receiving terminals globally.

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. 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 shipping assets are included in our two operating segments, Ships and Terminals and Infrastructure. Certain vessels are currently charted to third parties under long-term arrangements and are part of the Energos Formation Transaction; such vessels are included in our Ships segment. Vessels we operate at our Facilities, in our LNG supply chain or decide to sub-charter are included in our Terminals and Infrastructure segment. At the expiration of third-party charters of vessels owned by Energos, an entity formed in 2022 and described in more detail below, we plan to charter these vessels for our own use. We exclude these vessels from our Ships segment and include them in our Terminals and Infrastructure segment once we begin to charter the vessels directly from Energos. We maintain flexibility to deploy vessels in our Terminals and Infrastructure segment as needed to operate our LNG supply chain and serve our downstream customers or to sub-charter to monetize excess capacity.

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Set forth below are tables containing additional detail regarding each vessel in our operating segments:

Ships Segment:

Name

Type

Capacity (cubic meters of LNG)

Owner

Contract Type

Location

Energos Igloo

FSRU

170,000

Energos

Lease

The Netherlands

Energos Eskimo

FSRU

161,000

Energos

Lease

Kingdom of Jordan

Nusantara Regas Satu

FSRU

125,000

Energos

Lease

Indonesia

Terminals and Infrastructure Segment:

Name

Type

Capacity (cubic meters of LNG)

Owner

Contract Type

Location

Orion Sea

LNGC / FSU

174,000

JP Morgan

Lease

Various

Cobia LNG

LNGC / FSU

174,000

Cheniere / TMS Cardiff Gas

Lease

Various

Energy Endurance

LNGC / FSU

174,000

Alpha Gas

Lease

Various

Hoegh Gallant

FSRU

170,000

Hoegh LNG

Lease

Jamaica

Energos Celsius

FSRU

161,000

Energos

Lease

Brazil

NFE Penguin

LNGC / FSU

161,000

Energos

Lease

Mexico

Gaslog Singapore

LNGC / FSU

155,000

Gaslog

Lease

U.S. Virgin Islands

Energos Maria

LNGC / FSU

146,000

Energos

Lease

Various

Energos Grand

LNGC / FSU

146,000

Energos

Lease

Mexico

Energos Winter

FSRU

138,000

Energos

Lease

Brazil

Energos Princess

LNGC / FSU

138,000

Energos

Lease

Various

Energos Freeze

FSRU

126,000

Energos

Lease

Drydock

Coral Encanto

LNGC / FSU

30,000

Anthony Veder

Lease

Various

CNTIC Vpower Global

LNGC / FSU

30,000

CNTIC Vpower Holdings

Lease

Various

Avenir Accolade

LNGC / FSU

7,500

Avenir

Lease

Various

Coral Anthelia

LNGC / FSU

6,500

Anthony Veder

Lease

Various

We also lease, own and operate various operating service vessels, tugboats and other vessels to support our global operations.

Our Current Customers

Our downstream customers are, and we expect future customers to be, a mix of power, transportation and industrial users of natural gas and LNG, as well as local power generation, distribution companies, including private and governmental owned or controlled. We seek to substantially reduce our customers’ fuel costs while providing them with a cleaner-burning, more environmentally-friendly fuel source. We also intend to sell power and steam directly to some of our customers. In addition, we provide development services to some customers for the conversion or development of natural gas-fired power generation in connection with long-term agreements to supply natural gas or LNG to the customer.

We seek to enter into long-term take-or-pay contracts to deliver natural gas or LNG. Pricing for any particular customer depends on the size of the customer, purchased volume, the customer’s credit profile, the complexity of the delivery and the infrastructure required to deliver it.

We continue to have significant concentrations in revenue. Revenue from three customers constituted 48% of total revenue in 2024; no other customers comprised more than 10% of our revenue. For the year ended December 31, 2023, revenue from two significant customers constituted 47% of our total revenue. For the year ended December 31, 2022, revenue from two significant customers constituted 42% of our total revenue.

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We have several contracts with government-affiliated entities in the countries in which we operate. In Jamaica, we have gas sales agreements with JPS and SJPC. In Puerto Rico, we have a fuel sale and purchase agreement with PREPA, and Genera operates and maintains PREPA's thermal generation assets. In Mexico, we have entered into a gas sales agreement with CFE. In Nicaragua, we have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, some of which are wholly or partially owned or controlled by governmental entities. In Brazil, we have entered into various power purchase agreements with local distribution companies, some of which are wholly or partially owned or controlled by governmental entities.

Competition

In marketing LNG and natural gas, we compete for sales of LNG and natural gas primarily with LNG distribution companies who focus on sales of LNG without our integrated approach which includes development services and power. We also compete with a variety of natural gas marketers who may have affiliated distribution partners, including:

•major integrated marketers whose advantages include large amounts of capital and the ability to offer a wide range of services and market numerous products other than natural gas;

•producer marketers who sell natural gas they produce or which is produced by an affiliated company;

•small geographically focused marketers who focus their marketing on the geographic area in which their affiliated distributor operates; and

•aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.

Despite these competitors, we do not expect to experience significant competition for our LNG logistics services with respect to the Facilities to the extent we have entered into fixed GSAs or other long-term agreements we serve through the Facilities. If and when we have to replace our agreements with our counterparties, we may compete with other then-existing LNG logistics companies for these customers.

In purchasing LNG, we compete for supplies of LNG with:

•large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources;

•oil and gas producers who sell or control LNG derived from their international oil and gas properties; and

•purchasers located in other countries where prevailing market prices can be substantially different from those in the United States.

Government Regulation

Our infrastructure business and operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws, as well as foreign regulations and laws. These laws require, among other things, consultations with appropriate federal, state and other agencies and that we obtain, maintain and comply with applicable permits, approvals and other authorizations for the siting and conduct of our business. These regulatory requirements increase our costs of operations and construction, and failure to comply with such laws could result in consequences such as substantial penalties and/or the issuance of administrative orders to cease or restrict operations until we are in compliance.

DOE Export

The DOE issued an order authorizing us, through our subsidiary, NFEnergía LLC, to import LNG from various international sources by vessel at our San Juan Facility up to a total volume equivalent to 80 Bcf of natural gas over the two-year period beginning March 26, 2020 which we did in 2022 and will start the process of renewing it again in 2024. NFEnergía LLC must renew its authorization every two years. Imports of LNG are deemed to be consistent with the public interest under Section 3 of the Natural Gas Act (“NGA”) and applications for such imports must be granted without modification or delay. In August 2024, we received authorization from the DOE to export up to 1.4 million tonnes per annum of LNG to non-FTA countries from our Altamira Facility for a term of five years.

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FERC Authorization

The Federal Energy Regulatory Commission (“FERC”) regulates the siting, construction and operation of “LNG terminals” under NGA Section 3. In consultation with our outside counsel and, where appropriate, FERC staff, we have designed and constructed our U.S. facilities so that they do not meet the statutory definition of an “LNG terminal” as interpreted by FERC pursuant to its case law. On March 19, 2021, as upheld on rehearing on July 15, 2021, FERC determined that our San Juan Facility is subject to its jurisdiction and 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. The FERC orders were affirmed by the United States Court of the Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect and on January 30, 2024, FERC reaffirmed the order allowing the construction and operation to continue.

On September 26, 2024, the United States Coast Guard (“USCG”) filed a Letter of Recommendation with FERC in which it assessed our Letter of Intent dated April 12, 2024, and our Waterway Suitability Assessment, dated August 26, 2024, in respect of future ship to ship transfers with alternative vessels, and recommended against the allowance of the proposed operations. Further, the USCG issued a Letter of Warning in respect of our ongoing ship to ship transfers of LNG operations within the San Juan port limits. On October 21, 2024, we filed an appeal with the USCG under 33 CFR 160.7 and we received a response from the USCG on December 23, 2024 denying our appeal. In December 2024 and February 2025, we submitted an updated Letter of Intent and Waterway Suitability Assessments detailing our alternative operations 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.

Pipeline and Hazardous Materials Safety Administration

Many LNG facilities are also subject to regulation by the Department of Transportation (“DOT”), through PHMSA; PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of “pipeline facilities,” which PHMSA has defined to include certain LNG facilities that liquefy, store, transfer or vaporize natural gas transported by pipeline in interstate or foreign commerce. PHMSA has promulgated detailed, comprehensive regulations governing LNG facilities under its jurisdiction at Title 49, Part 193 of the United States Code of Federal Regulations. These regulations address LNG facility siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. Variances from these regulations may require obtaining a special permit from PHMSA, the issuance of which is subject to public notice and comment and consultation with other federal agencies, which could result in delays, perhaps substantial in length, to the construction of our facilities where such variances are needed; additionally, PHMSA may condition, revoke, suspend or modify the special permits it issues.

In December 2019, PHMSA granted a special permit to one of our subsidiaries to ship LNG by rail, which would allow us to transport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels. This special permit expired on November 30, 2021, at which time our subsidiary applied for its renewal. On April 24, 2023, PHMSA issued a decision denying this special permit renewal request. On July 24, 2020, PHMSA issued a final rule authorizing the nationwide transportation of LNG by rail in DOT–113C120W specification rail tank cars, subject to all applicable requirements and certain additional operational controls. The appeal period for the special permit has expired. However, in November 2021, PHMSA issued a proposed rule to rescind the final rule authorizing nationwide transportation. In September 2023, DOT promulgated a rule that suspends authorization of LNG transportation by rail pending the earlier of either completion of a rulemaking evaluating potential modifications to requirements governing tank

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car transportation of LNG under the Hazardous Materials Regulations at 49 C.F.R. Parts 171-180 or by June 30, 2025, whichever is earlier. In January 2025, the Washington DC Court of Appeals vacated the rule allowing LNG transportation by rail. We have the ability to transport LNG from our Pennsylvania Facility via truck, and this logistical solution is available to us should we be unable to transport by rail.

Environmental Regulation

Our infrastructure and operations are subject to various international, federal, state and local laws and regulations as well as foreign laws and regulations relating to the protection of the environment, natural resources and human health. These laws and regulations may require the installation of controls on emissions and structures to prevent or mitigate any potential harm to human health and the environment or require certain protocols to be in place for mitigating or responding to accidental or intentional incidents at certain facilities. These laws and regulations may also lead to substantial penalties for noncompliance and substantial liabilities for incidents arising out of the operation of our facilities. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.

Other local laws and regulations, including local zoning laws, critical infrastructure regulations and fire protection codes, may also affect where and how we operate.

The costs of compliance with these requirements are not expected to have a material adverse effect on our business, financial condition or results of operations.

Environmental Regulation in Mexico

Mexican law comprehensively regulates the energy sector, including all aspects of the receipt, delivery, import, export, storage, marketing, liquefaction, and regasification of LNG; the generation and transmission of electricity; and the environmental impact of all these activities. Various Mexican federal agencies regulate these activities including, the Ministry of Energy, Ministry of the Navy, Ministry of Environment and Natural Resources, Ministry of Infrastructure, Communication and Transportation, the Energy Regulatory Commission, and the Safety, Energy & Environment Agency. State and local agencies are also involved in regulating these activities, issuing permits and authorizing the use of property for such purposes. To obtain permits and approvals required under Mexican law for the development, construction and operation of energy-related projects in Mexico, such projects must first complete environmental and social impact assessments, which are subject to the evaluation by the authorities. In addition, all hydrocarbon projects must include an environmental risk assessment, which is based on a thorough risk analysis made prior to each stage and aimed at identifying potential design and operational hazards. Mexican law allows the governmental entities and, in certain cases, individuals, to pursue claims against violations of environmental laws or permits issued pursuant to such laws.

Environmental Regulation in Jamaica

Our operations in Jamaica are governed by various environmental laws and regulations. These laws and regulations are largely implemented through the National Environment and Planning Agency and cover discharges of pollutants, regulation of air emissions, discharges and treatment of wastewater, storage of fuels, and responses to industrial emergencies involving hazardous materials. The level of environmental regulation in Jamaica has increased in recent years, and the enforcement of environmental laws is becoming more stringent. Compliance has not had a material adverse effect on our business, operations, or financial condition, but we cannot assure you that this will be the case in the future. Jamaica is also in the process of developing a law to govern the receipt, storage, processing and distribution of natural gas, as well as requirements for the licensing, construction, and operation of natural gas facilities and transportation.

Environmental Regulation in Nicaragua

The regulation of activities with the potential to impact the environment in Nicaragua are largely regulated by the Natural Resource and Environment Ministry. Nicaragua regulates many areas of environmental protection. In order to obtain various permits for operations, a project must complete environmental and social impact analyses according to Nicaraguan law. While Nicaragua does not currently have any legislation specifically addressing the receipt, handling, and distribution of natural gas, such laws may be passed in the future.

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Environmental Regulation in Ireland

The operation of the facilities will be regulated via additional licenses and consents including from the Environmental Protection Agency (EPA); the Commission for Regulation of Utilities (CRU); the Health and Safety Authority (HSA); and the Local Planning Authority (Kerry Co. Council (KCC)). Additionally, the Shannon Foynes Port Company (SFPC) has statutory jurisdiction over marine activities. The LNG Terminal and Power Plant will also have to operate within the provisions of a number of codes, such as the EirGrid Transmission Network Grid Code, Single Electricity Market Trading and Settlement Code and GNI Code of Operations. We are in the process of applying for all these necessary permits, licenses and consents to build and complete the Ireland Facility.

The issuance of many of these permits may be subject to administrative or judicial challenges, including by non-governmental groups that act on behalf of citizens. We intend to begin construction of the Ireland Facility after we have obtained planning permission and secured contracts with downstream customers for volumes that are sufficient to support the development of the Ireland Facility.

Environmental Regulation in Brazil

Our operations in Brazil are governed by various environmental laws and regulations. These laws and regulations cover social and environmental impacts, air emissions, discharges and treatment of residues, and emergency response, among others. According to Brazilian environmental legislation, the environmental licensing for energy generation activities must follow three stages: a Preliminary License that authorizes the design of the project and the location of the enterprise, an Installation License that authorizes the start of the implementation activities and, an Operating License, which authorizes the actual start of the activity. At each stage, specific environmental plans and studies are required to assess and mitigate the impacts on the environment. In addition, other authorizations may be required by environmental authorities on a local (municipal), state and federal level, including, but not limited to, permits to suppress vegetation, authorization for fauna management, and permission to address and/or otherwise mitigate impacts on affected communities, and others.

Environmental Regulation in Puerto Rico

Our operations in Puerto Rico are subject to various Puerto Rico laws and regulations relating to the protection of the environment, natural resources and human health. Puerto Rico has enacted a number of different statutes and regulations in order to implement the requirements of federal environmental laws on operations on the island. Environmental statutes and regulations are largely implemented by the Puerto Rico Department of Environment and Natural Resources. As part of its operations, our San Juan Facility is required to comply with Clean Water Act requirements for stormwater and Clean Air Act requirements for facility emission sources. These laws and their related regulations require permits for the operation of the facilities and the implementation of mitigation measures to address environmental impacts of facility operations. Additionally, our operations in Puerto Rico are subject to regulation by the Department of Transportation and Public Works (“DTOP”). DTOP has been delegated authority from DOT to regulate both the distribution of natural gas through road transportation and facilities that operate natural gas pipelines. All deliveries of LNG by truck in Puerto Rico are subject to federal requirements for the ISO containers that hold the LNG and for the transport of the LNG by truck. Any expansion or increased stringency of these requirements may increase compliance costs for our operations in Puerto Rico.

U.S. and International Maritime Regulations of LNG Vessels

The International Maritime Organization (“IMO”) is the United Nations agency that provides international regulations governing shipping and international maritime trade. The requirements contained in the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”) promulgated by the IMO govern the shipping of our LNG cargos and the operations of any vessels we use in our operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a policy for safety and environmental protection setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.

Vessels that transport gas, including LNGCs, are also subject to regulation under various international programs such as the International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (the “IGC Code”) published by the IMO. The IGC Code provides a standard for the safe carriage of LNG and certain other liquid gases by prescribing the design and construction standards of vessels involved in such carriage, and includes specific air emissions limits, including on sulfur oxide and nitrogen oxide emissions from ship exhausts.

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We contract with leading vessel providers in the LNG industry and look to them to ensure that each of our chartered vessels is in compliance with applicable international and in-country requirements. Nevertheless, the IMO continues to review and introduce new regulations and we cannot with any certainty predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.

Import and Export Control Laws and Regulations

We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Latin America, Europe and the other countries in which we seek to do business. We must also comply with trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. For example, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua and between 2018 and 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the governments of Nicaragua and Venezuela. Following the invasion of Ukraine by Russia in 2022, U.S. European, U.K. and other governmental authorities imposed a number of sanctions against entities and individuals in Russia or connected to Russia, including sanctions specifically targeting the Russian oil and gas industry. Violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to, (i) having to suspend our development or operations on a temporary or permanent basis, (ii) being unable to recuperate prior invested time and capital or being subject to lawsuits, or (iii) investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.

Anti-corruption Laws and Regulations

We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), the U.K. Bribery Act and local anti-bribery laws, which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently operate present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Brazil and Mexico. Furthermore, our strategy has been, and continues to be, dependent in part on our ability to expand our operations in additional emerging markets, including in Latin America, Asia and Africa. Efforts to expand our operations in these markets could expose us to additional risks related to anti-corruption laws and regulations. Although we have adopted policies and procedures that are designed to assist us, our officers, directors, employees and other intermediaries in complying with the FCPA and other anti-corruption laws and regulations, developing and implementing policies and procedures is a complex endeavor, particularly given the high level of complexity of these laws and regulations. There is no assurance that these policies and procedures have or will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our officers, directors, employees and other intermediaries with respect to our business or any businesses that we may acquire, particularly in high risk jurisdictions.

Suppliers and Working Capital

We expect to continue to supply our downstream customers with LNG and natural gas sourced from a combination of long-term, LNG contracts with attractive terms, purchases on the open market and our own FLNG production.

Seasonality

Our operations can be affected by seasonal weather, which can temporarily affect our revenues, the delivery of LNG and the construction of our Facilities. For example, activity in the Caribbean is often lower during the North Atlantic hurricane season of June through November, and following a hurricane, activity may decrease further as there may be business interruptions as a result of damage or destruction to our Facilities or the countries in which we operate. The Brazilian electric integrated system is largely dependent on hydro-generated power, which is affected during dry seasons, requiring other sources of power, such as natural gas-fired thermal power station, to dispatch more or less based on the amount of the rainfall during any period. Due to these seasonal fluctuations, results of operations for individual quarterly

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periods may not be indicative of the results that may be realized on an annual basis. Severe weather in the countries where our Facilities are located may delay completion of our Facilities under development and related infrastructure, adversely affect our operations of our Facilities and affect the markets in which we operate. We are also particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in particular with respect to fleet operations, floating offshore liquefaction units and other infrastructure we may develop in connection with our Fast LNG technology.

Our Insurance Coverage

We maintain customary insurance coverage for our business and operations. Our domestic insurance related to property, equipment, automobile, general liability and workers’ compensation is provided through policies customary for the business and exposures presented, subject to deductibles typical in the industry. Internationally, we also maintain insurance, including policies related to property, equipment, automobile, marine, pollution liability, general liability and the portion of workers’ compensation not covered under a governmental program.

We maintain property insurance, including named windstorm and flood, related to the operation of the Miami Facility, San Juan Facility, the La Paz Facility, and the Jamaica Facilities and builders risk insurance at our Facilities under development.

Human Capital

We had 682 NFE full-time employees and 722 Genera full-time employees as of December 31, 2024. We depend upon our skilled workforce to manage, operate and plan for our business. Recruitment and retention of talent across our company enables growth and innovation across a multitude of corporate initiatives, and this is one of our top priorities.

Our Human Resources team oversees human capital management, including talent attraction and retention, compensation and bonuses, employee relations, employee engagement and training and development in the various countries in which we operate.

Culture and Inclusivity

Our employees are critical to the success of our business. We value a broad range of perspectives in our workplace and are committed to maintaining culture where our employees feel valued, welcomed and can thrive. We are subject to various federal, state and local laws related to labor and employment, including matters related to workplace discrimination, harassment and unlawful retaliation in the jurisdictions in which we operate. We have developed and published our Code of Business Conduct, which sets out a guideline in connection with these matters and reflects our high expectations for an ethical workplace where employees are treated with dignity and respect. Because labor and employment laws and regulations can differ among the jurisdictions in which we operate, our Code of Business Conduct operates as a guideline for practices, but does not cover every legal aspect in each of our locations.

We are committed to advancing our culture of inclusivity through the following actions, among others:

•collecting and analyzing employee workforce data;

•conducting harassment trainings; and

•expanding employee benefits to include additional health programs such as mental health support and medical concierge services.

Employee Health, Safety and Wellness

We are subject to various health, safety, and environmental laws and regulations in the jurisdictions in which we operate. We have developed and published a Health, Safety, Security and Environment (HSSE) Strategic Framework, which sets out a guideline in connection with risk management, education/training, emergency response, incident management, performance measurement and other key programmatic drivers. Because health, safety, and environmental laws and regulations can differ among the jurisdictions in which we operate, our HSSE Strategic Framework operates as a guideline for practices, but is not binding or required. We also have developed and published a contractor safety management handbook for our contractors.

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For the year ended December 31, 2024, we had no fatalities across our operating sites.

Property

We lease space for our offices in New York, New York, Houston, Texas, Rio de Janeiro, Brazil, Mexico City, Mexico and San Juan, Puerto Rico, and in other regions in which we operate. We own the properties on which our Pennsylvania Facility will be located. Additionally, the properties on which our Facilities, including the CHP Plant, are located are generally subject to long-term leases and rights-of-way. Our leased properties are subject to various lease terms and expirations.

Sustainability

Since our founding in 2014, sustainability has been at the core of our mission and vision. We believe that a sustainable future built on positive energy is the way forward. To advance both our business model and the interests of our stakeholders— including our people, shareholders and investors, partners, the communities we serve, and the wider public—we have established four key sustainability goals: (i) protect and preserve the environment, (ii) empower people worldwide, (iii) invest in communities, and (iv) become a leading provider of very-low-carbon energy. Our sustainability initiatives and investments under each of these goals are highlighted below.

Protect and Preserve the Environment

We are committed to our goal to protect and preserve the environment, and we progress this goal by providing cleaner energy solutions around the world. With our projects, we strive to reduce carbon emissions and increase energy efficiency. By helping our customers convert from traditional fuels such as oil or coal to LNG as their energy source, we seek to reduce air-polluting emissions of nitrogen oxide (NOx), carbon dioxide (CO2), sulfur oxide (SOx), and fine particulate matter, among others. Moreover, we believe that the use of LNG as a complement to renewable power options is helping the transition to a sustainably-sourced energy future.

Empower People Worldwide

We are committed to our goal to provide access to affordable, reliable, cleaner energy. To that end, we help our customers customize and implement LNG energy solutions designed to lower their energy costs, reduce their environmental footprint, and improve their energy efficiency, either by converting their existing power generation to LNG or by building brand-new gas-fired facilities. In addition, we seek to provide a reliable supply of LNG to our customers, wherever located, through our established, integrated LNG logistics chain.

Invest in Communities

We are committed to our goal to improve lives and support people, especially in the communities where we operate. For example, through our New Fortress Energy Foundation, we seek to strengthen our communities by (i) investing in education to help support the next generation of leaders; (ii) providing industry training programs to help create and sustain a well-equipped workforce; and (iii) giving financially to community causes that enhance quality of life, including reducing poverty, hunger, and inequities. For the year-ended December 31, 2024, we:

•Hired 186 full-time employees globally, prioritizing local hires in each region;

•Awarded 60 engineering and STEM scholarships across three universities in Jamaica;

•Provided financial aid for 2,000 students, covering tuition, school supplies, medical, and college exams in Jamaica;

•Supported 1,255 students participating in STEM activities in Jamaica

•Developed the workforce with internship programs and professional courses for 5 students in Jamaica;

•Provided medical screenings to 500 children in Jamaica;

•Donated essential supplies to 50 elderly individuals in Mexico;

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•Donated towards a Children’s Day event to celebrate 300 children in Mexico;

•Donated towards the development of a multipurpose field for 150 children in Nicaragua;

•Sponsored an event for 200,000 students to explore the field of natural gas in Brazil;

• Donated towards the construction of a community center to support 5,000 children and adults in Brazil; and

•Empowered local communities by hosting events and activities for 400 families in Brazil.

Toward a Low Carbon Future

As we work to reduce greenhouse gas (GHG) emissions for our customers around the world, our goals are to reach net zero carbon emissions by 2030 for Scope 1 and 2 emissions for our initial Facilities and be one of the world’s leading providers of low-carbon energy. We believe that natural gas remains a cost-effective and environmentally-friendly complement for intermittent renewable energy, aiding the growth of these technologies. Over time, we believe that hydrogen will play an increasingly significant role in the decarbonization of hard to abate corners of the global economy supporting renewable development and displacing fossil fuels. To that end, we formed a division, which we call ZeroParks, to evaluate promising technologies and pursue initiatives that will position us to capitalize on this emerging industry. In January 2025, the U.S. Treasury Department released the final rules for clean hydrogen production tax credits. We are in the process of analyzing these rules and the impact they may have on our clean hydrogen business.

Available Information

We are required to file or furnish any annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The SEC maintains an internet website that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC, including this Annual Report, at www.sec.gov.

We also make available free of charge through our website, www.newfortressenergy.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8- K, and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report.

Additionally, we have made our annual Sustainability Report and environmental, social and governance (“ESG”) related documents available on our website, www.newfortressenergy.com, to provide more detailed information regarding our human capital programs and initiatives as well as our efforts to manage ESG issues.

Item 1A. Risk Factors

An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below. If any of the following risks were to occur, the value of our Class A common stock could be materially adversely affected or our business, financial condition and results of operations could be materially adversely affected and thus indirectly cause the value of our Class A common stock to decline. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business and the value of our Class A common stock. As a result of any of these risks, known or unknown, you may lose all or part of your investment in our Class A common stock. The risks discussed below also include forward-looking statements, and actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement on Forward-Looking Statements.”

Summary Risk Factors

Some of the factors that could materially and adversely affect our business, financial condition, results of operations or prospects include the following:

Risks Related to Our Business

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•Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors;

•We are subject to various construction risks;

•Operation of our infrastructure, facilities and vessels involves significant risks;

•We depend on third-party contractors, operators and suppliers;

•Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy;

• We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation;

• Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction;

• When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project;

• Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements;

• Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects;

• Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;

• We may not be able to convert our anticipated customer pipeline into binding long-term contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate;

• Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers;

• Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses;

• We are dependent on third-party LNG suppliers and the development of our own portfolio is subject to various risks and assumptions;

•LNG that is processed, transported and/or stored on FSRUs and transported via pipeline is subject to risk of loss or damage;

•We rely on tankers and other vessels outside of our fleet for our LNG transportation and transfer;

•Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings may decline;

•The operation of our vessels is dependent on our ability to deploy our vessels to an NFE terminal or to long-term charters;

• We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve;

•Technological innovation may impair the economic attractiveness of our projects;

• Our Fast LNG technology is not yet proven and we may not be able to implement it as planned or at all;

• Our data center infrastructure business has no operating history, and it may not be profitable;

•We have incurred, and may in the future incur, a significant amount of debt;

• Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms;

•Existing and future environmental, social, health and safety laws and regulations could result in increased or more stringent compliance requirements, which may be difficult to comply with or result in additional costs and may otherwise lead to significant liabilities and reputational damage;

•We are subject to numerous governmental export laws, and trade and economic sanctions laws and regulations, and anti-corruption laws and regulation;

•We may incur impairments to long-lived assets;

• Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate;

•Increasing transportation regulations may increase our costs and negatively impact our results of operations;

•Our chartered vessels operating in certain jurisdictions, including the United States, now or in the future, may be subject to cabotage laws, including the Merchant Marine Act of 1920, as amended (the “Jones Act”);

•Information technology failures and cyberattacks could affect us significantly;

•Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.

•Our success depends on key members of our management;

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•We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us;

•Our business could be affected adversely by labor disputes, strikes or work stoppages;

Risks Related to the Jurisdictions in Which We Operate

•We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate;

• Our financial condition and operating results may be adversely affected by foreign exchange fluctuations;

Risks Related to Ownership of Our Class A Common Stock

•The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders;

•A small number of our original investors have the ability to direct a significant amount of our common stock, and their interests may conflict with those of our other stockholders;

•The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and we do not expect to pay dividends for the foreseeable future;

•The incurrence or issuance of debt which ranks senior to our Class A common stock upon our liquidation and future issuances of equity or equity-related securities, which would dilute the holdings of our existing Class A common stockholders and may be senior to our Class A common stock for the purposes of making distributions, periodically or upon liquidation, may negatively affect the market price of our Class A common stock;

•Sales or issuances of our Class A common stock could adversely affect the market price of our Class A common stock;

General Risks

•We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest;

•We may engage in mergers, sales and acquisitions, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value;

•A change in tax laws in any country in which we operate could adversely affect us; and

•We have been and may be involved in legal proceedings and may experience unfavorable outcomes.

Risks Related to Our Business

Our ability to continue as a going concern is dependent upon our ability to complete certain transactions and delay capital expenditures

As discussed in note 2 to the financial statements, under ASC 205-40, when first assessing whether substantial doubt is raised about the entity’s ability to continue as a going concern, management cannot consider the potential mitigating effects of its plans that have not been fully implemented at the assessment date. Management has concluded that the Company’s current liquidity and forecasted cash flows (which exclude the effect of the Transactions as defined below), from operations are not sufficient to support, in full, obligations as they become due. Management has approved a plan to support its liquidity position by: (i) delaying certain discretionary payments, including planned capital expenditures and dividends, that are within management’s control, and (ii) continuously renewing the LNG cargo financing facility over the succeeding twelve months. Management’s plan also includes the availability of a backstop agreement that was executed in March 2025 and provides up to $100 million of availability. Management concluded that such plans are probable of being implemented and the Company will have sufficient liquidity to meet its obligations as they become due over the next twelve months from the date that the consolidated financial statements were issued. In addition to management’s plan outlined above, the Company continues to explore asset sales, settlement of claims and other strategic transactions (collectively, the “Transactions”) that seek to optimize the value of the Company’s portfolio while providing additional liquidity and cash flow to the Company. However, there are inherent uncertainties, as the execution of the Transactions are outside of management’s control and therefore there are no assurances that these transactions will be executed. Furthermore, there are inherent risks with the Company’s ability to continue to implement plans in future periods that will support its liquidity position, such as its ability to further extend the terms of vendor payments and other obligations.

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Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors.

Our business strategy relies on a variety of factors, including our ability to successfully market LNG, natural gas, steam, and power to our customers, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in the countries where we operate, and expand our projects and operations to other countries where we do not currently operate, among others. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control, including, among others:

•inability to achieve our target costs for the purchase, liquefaction and export of natural gas and/or LNG and our target pricing for long-term contracts;

• failure to develop strategic relationships;

• failure to obtain required governmental and regulatory approvals for the construction and operation of these projects and other relevant approvals;

• unfavorable laws and regulations, changes in laws or unfavorable interpretation or application of laws and regulations; and

• uncertainty regarding the timing, pace and extent of economic growth in the United States, the other jurisdictions in which we operate and elsewhere, which in turn will likely affect demand for crude oil and natural gas.

Furthermore, as part of our business strategy, we target customers who have not been traditional purchasers of natural gas, including customers in developing countries, and these customers may have greater credit risk than typical natural gas purchasers. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance.

Our strategy may evolve over time. Our future ability to execute our business strategy is uncertain, and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our ability to execute our business strategy and adversely affect our business, financial condition and results of operations.

We are subject to various construction risks.

We are involved in the development of complex small, medium and large-scale engineering and construction projects, including our facilities, liquefaction facilities, power plants, and related infrastructure, which are often developed in multiple stages involving commercial and governmental negotiations, site planning, due diligence, permit requests, environmental impact studies, permit applications and review, marine logistics planning and transportation and end-user delivery logistics. In addition to our facilities, these infrastructure projects can include the development and construction of facilities as part of our customer contracts. Projects of this type are subject to a number of risks including, among others:

•engineering, environmental or geological problems;

•shortages or delays in the delivery of equipment and supplies;

•government or regulatory approvals, permits or other authorizations;

•failure to meet technical specifications or adjustments being required based on testing or commissioning;

•construction, commissioning or operating accidents that could result in personal injury or loss of life;

•lack of adequate and qualified personnel to execute the project;

•weather interference; and

•potential labor shortages, work stoppages or labor union disputes.

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Furthermore, because of the nature of our infrastructure, we are dependent on interconnection with transmission systems and other infrastructure projects of third parties, including our customers, and/or governmental entities. Such third-party projects can be greenfield or brownfield projects, including modifications to existing infrastructure or increases in capacity to existing facilities, among others, and are subject to various construction risks and additional operational monitoring and balancing requirements that may impact the design of facilities to be constructed. Delays from such third parties or governmental entities could prevent connection to our projects and generate delays in our ability to develop our own projects. In addition, a primary focus of our business is the development of projects in foreign jurisdictions, including in locations where we have no prior development experience, and we expect to continue expanding into new jurisdictions in the future. These risks can be increased in jurisdictions where legal processes, language differences, cultural expectations, currency exchange requirements, political relations with the U.S. government, changes in the political views and structure, government representatives, new regulations, regulatory reviews, employment laws and diligence requirements can make it more difficult, time-consuming and expensive to develop a project. See “–Risks Related to the Jurisdictions in Which We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.”

The occurrence of any one of these factors, whatever the cause, could result in unforeseen delays or cost overruns to our projects. Delays in the development beyond our estimated timelines, or amendments or change orders to our construction contracts, could result in increases to our development costs beyond our original estimates, which could require us to obtain additional financing or funding and could make the project less profitable than originally estimated or possibly not profitable at all. Further, any such delays could cause a delay in our anticipated receipt of revenues, a loss of one or more customers, and our inability to meet milestones or conditions precedents in our customer contracts, which could lead to delay penalties and potentially a termination of agreements with our customers. We have experienced time delays and cost overruns in the construction and development of our projects as a result of the occurrence of various of the above factors, including most recently with our First LNG project in Altamira, Mexico, and no assurance can be given that we will not continue to experience in the future similar events, any of which could have a material adverse effect on our business, operating results, cash flows and liquidity.

Operation of our infrastructure, facilities and vessels involves significant risks.

Our existing infrastructure, facilities and vessels and expected future operations and businesses face operational risks, including, but not limited to, the following:

•performing below expected levels of efficiency or capacity or required changes to specifications for continued operations;

•breakdowns or failures of equipment or shortages or delays in the delivery of supplies;

•operational errors by trucks, including trucking accidents while transporting natural gas, LNG or any other chemical or hazardous substance;

•risks related to operators and service providers of tankers or tugs used in our operations;

•operational errors by us or any contracted facility, port or other operator of related third-party infrastructure;

•failure to maintain the required government or regulatory approvals, permits or other authorizations;

•accidents, fires, explosions or other events or catastrophes;

•lack of adequate and qualified personnel;

•potential labor shortages, work stoppages or labor union disputes;

•weather-related or natural disaster interruptions of operations;

•pollution, release of or exposure to toxic substances or environmental contamination affecting operations;

•inability, or failure, of any counterparty to any facility-related agreements to perform their contractual obligations;

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•decreased demand by our customers; and

•planned and unplanned power outages or failures to supply due to scheduled or unscheduled maintenance.

In particular, we are subject to risks related to the operation of power plants, liquefaction facilities, marine and other LNG operations with respect to our facilities, FSRU and LNG carriers, which operations are complex and technically challenging and subject to mechanical risks and problems. In particular, marine LNG operations are subject to a variety of risks, including, among others, marine disasters, piracy, bad weather, mechanical failures, environmental accidents, epidemics, grounding, fire, explosions and collisions, human error, and war and terrorism. An accident involving our cargos or any of our chartered vessels could result in death or injury to persons, loss of property or environmental damage; delays in the delivery of cargo; loss of revenues; termination of charter contracts; governmental fines, penalties or restrictions on conducting business; higher insurance rates; and damage to our reputation and customer relationships generally. Any of these circumstances or events could increase our costs or lower our revenues. If our chartered vessels suffer damage as a result of such an incident, they may need to be repaired. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built and result in higher than anticipated operating expenses or require additional capital expenditures. The loss of earnings while these vessels are being repaired would decrease our results of operations. If a vessel we charter were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage could have a material adverse effect on our reputation, our business, our results of operations and cash flows and weaken our financial condition. Our offshore operating expenses depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control. Other factors, such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements, could also increase operating expenditures. Future increases to operational costs are likely to occur. If costs rise, they could materially and adversely affect our results of operations. In addition, operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm our business, financial condition and results of operations.

We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, our facilities or assets.

We depend on third-party contractors, operators and suppliers.

We rely on third-party contractors, equipment manufacturers, suppliers and operators for the development, construction and operation of our projects and assets. We have not yet entered into binding contracts for the construction, development and operation of all of our facilities and assets, and we cannot assure you that we will be able to enter into the contracts required on commercially favorable terms, if at all, which could expose us to fluctuations in pricing and potential changes to our planned schedule. If we are unable to enter into favorable contracts, we may not be able to construct and operate these assets as expected, or at all. Furthermore, these agreements are the result of arms-length negotiations and subject to change. There can be no assurance that contractors and suppliers will perform their obligations successfully under their agreements with us. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. Although some agreements may provide for liquidated damages if the contractor or supplier fails to perform in the manner required with respect to its obligations, the events that trigger such liquidated damages may delay or impair the completion or operation of the facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment, including, among others, any covenants or obligations by us to pay liquidated damages or penalties under our agreements with our customers, development services, the supply of natural gas, LNG or steam and the supply of power, as well as increased expenses or reduced revenue. Such liquidated damages may also be subject to caps on liability, and we may not have full indemnification from our contractors to compensate us for such payments and other consequences. We may hire contractors to perform work in jurisdictions where they do not have previous experience, or contractors we have not previously hired to perform work in jurisdictions we are beginning to develop, which may lead to such contractors being unable to perform according to their respective agreements. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. If we are unable to construct and commission our facilities and assets as expected, or, when and if constructed, they do not accomplish our goals or

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performance expectations, or if we experience delays or cost overruns in design, construction, commissioning or operation, our business, operating results, cash flows and liquidity could be materially and adversely affected.

Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.

Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional or shale natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. LNG prices have increased materially in the past, including in August 2021 through the end of 2022, and global events, such as Russia’s invasion of Ukraine and global inflationary pressures, have generated further energy pricing volatility, which have had and may in the future have an adverse effect on market pricing of LNG and global demand for our products, as well as our ability to remain competitive in the markets in which we operate. Potential expansion in the Caribbean, Latin America and other parts of the world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. In Brazil, hydroelectric power generation is the predominant source of electricity and LNG is one of several other energy sources used to supplement hydroelectric generation. The success of our operations is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to our customers at a lower cost than the cost to deliver other alternative energy sources.

Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean and Latin America, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean, Latin America and other countries where we operate or seek to operate. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to other markets or from or to our competitors’ LNG facilities. Natural gas also competes with other sources of energy, including coal, oil, nuclear, hydrogen, hydroelectric, wind and solar energy, which may become available at a lower cost in certain markets. As a result of these and other factors, natural gas may not be a competitive source of energy in the markets we intend to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect our ability to deliver LNG or natural gas to our customers on a commercial basis, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

We operate in a highly regulated environment and our operations could be adversely affected by actions by governmental entities or changes to regulations and legislation.

Our business is highly regulated and subject to numerous governmental laws, rules, regulations and requires permits, authorizations and various governmental and agency approvals, in the various jurisdictions in which we operate, that impose various restrictions and obligations that may have material effects on our business and results of operations. Each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the federal, state or local level, or by new or modified regulations that may be implemented under existing law. The nature and extent of any changes in these laws, rules, regulations and permits may be unpredictable, have retroactive effects, and may have material effects on our business. Future legislation and regulations or changes in existing legislation and regulations, or interpretations thereof, such as those relating to power, natural gas or LNG operations, including exploration, development and production activities, liquefaction, regasification or transportation of our products, could cause additional expenditures, restrictions and delays in connection with our operations as well as other future projects, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

In addition, these rules and regulations are assessed, managed, administered and enforced by various governmental agencies and bodies, whose actions and decisions could adversely affect our business or operations. In the United States and Puerto Rico, approvals of the DOE under Section 3 of the NGA, as well as several other material governmental and regulatory permits, approvals and authorizations, including under the CAA and the CWA and their state analogues, may be required in order to construct and operate an LNG facility and export LNG. Permits, approvals and authorizations obtained

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from the DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional requirements may be imposed. On July 1, 2024, the Western District of Louisiana stayed the pause in its entirety, The Biden Administration appealed the ruling in August 2024 and litigation remains ongoing. On December 17, 2024, the DOE publicly released a multi-volume study of its view of the potential effects of U.S. LNG exports on the domestic economy; U.S. households and consumers; communities that live near locations where natural gas is produced or exported; domestic and international energy security, including effects of U.S. trading partners; and the environment and climate. The DOE stated that it intends to use this study to inform its public interest review of and future decisions regarding exports to non-FTA nations. The study is subject to a sixty-day public comment period and the finalization of the study and any application of it in future decision-making will be determined by the new presidential administration. Although President Trump oppose the DOE pause on export authorizations and advocated prompt of new authorizations during his presidential campaign, we expect that most DOE long-term, non-FTA authorizations will continue to experience delays. While the Trump Administration is widely expected to support LNG exports, there can be no assurance as to its views of the recently released DOE study or its future policies, or the impact of those policies on our existing and future projects.

Certain federal permitting processes may trigger the requirements of the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions that have the potential to significantly impact the environment. Compliance with NEPA may extend the time and/or increase the costs for obtaining necessary governmental approvals associated with our operations and create independent risk of legal challenges to the adequacy of the NEPA analysis, which could result in delays that may adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and profitability. On July 15, 2020, the White House Council on Environmental Quality issued a final rule revising its NEPA regulations. The Council on Environmental Quality has announced that it is engaged in an ongoing and comprehensive review of the revised regulations and is assessing whether and how the Council may ultimately undertake a new rulemaking to revise the regulations. The impacts of any such future revisions that may be adopted are uncertain and indeterminable for the foreseeable future. On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. On March 19, 2021, as upheld on rehearing on July 15, 2021, FERC determined that our San Juan Facility is subject to its jurisdiction and directed us to file an application for authorization to operate the San Juan Facility but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. 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.

We may not comply with each of these requirements in the future, or at all times, including any changes to such laws and regulations or their interpretation. The failure to satisfy any applicable legal requirements may result in the suspension of our operations, the imposition of fines and/or remedial measures, suspension or termination of permits or other authorization, as well as potential administrative, civil and criminal penalties, which may significantly increase compliance costs and the need for additional capital expenditures.

Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.

The design, construction and operation of our infrastructure, facilities and businesses, including our FSRUs, FLNG units and LNG carriers, the import and export of LNG, exploration and development activities, and the transportation of natural gas, among others, are highly regulated activities at the national, state and local levels and are subject to various approvals and permits. The process to obtain the permits, approvals and authorizations we need to conduct our business, and the interpretations of those rules, is complex, time-consuming, challenging and varies in each jurisdiction in which we operate. We may be unable to obtain such approvals on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations. Many of these permits, approvals and authorizations require public notice and comment before they can be issued, which can lead to delays to respond to such comments, and even potentially to revise the permit application. Jurisdiction-specific employment, labor, and subcontracting laws may also affect contracting strategies and impact construction and operations. We may also be (and have been in select circumstances) subject to local opposition, including citizens groups or non-governmental organizations such as environmental groups, which may create delays and challenges in our permitting process and may attract negative publicity, which may create an adverse impact on our reputation. In addition, such rules change frequently and are often subject to discretionary interpretations, including administrative and judicial challenges by regulators, all of which may make compliance more difficult and may increase the length of time it takes to receive regulatory approval for our operations, particularly in countries where we operate, such as Mexico and Brazil. For example, in Mexico, we have obtained substantially all permits but are awaiting final approvals for our power plant and permits necessary to operate our terminal. In connection with our application to the U.S. Maritime Administration ("MARAD") related to our FLNG project off the coast of Louisiana (as discussed further below),

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MARAD announced it had initially paused the statutory 356-day application review timeline on August 16, 2022 pending receipt of additional information, and restarted the timeline on October 28, 2022. MARAD issued a second stop notice on November 23, 2022 and on December 22, 2022, MARAD issued a third data request for supplemental information. Following review of NFE's response to the December 2022 data requests, MARAD extended the stop-clock on February 21, 2023 pending clarification of responses and receipt of additional information. In addition, jurisdiction-specific employment, labor, and subcontracting laws may also affect contracting strategies and impact construction and operations. No assurance can be given that we will be able to obtain approval of all applications or receive the required permits, approvals and authorizations from governmental and regulatory agencies related to our projects with favorable terms on a timely basis or at all. 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. We cannot make any assurance as to if or when we will receive these permits, which are needed prior to commencing certain construction activities related to the facility. Any administrative and judicial challenges to our permits can delay and protract the process for obtaining and implementing permits and can also add significant costs and uncertainty. We cannot control the outcome of any review or approval process, including whether or when any such permits and authorizations will be obtained, the terms of their issuance, or possible appeals or other potential interventions by third parties that could interfere with our ability to obtain and maintain such permits and authorizations or the terms thereof. Furthermore, we are developing new technologies and operate in jurisdictions that may lack mature legal and regulatory systems and may experience legal instability, which may be subject to regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to our business and new technology, which can result in difficulties and instability in obtaining or securing required permits or authorizations. In addition, our LNG transportation activities are subject to broad array of regulations, and our operations are dependent upon obtaining and maintaining required permits and authorizations,. For example, the United States Coast Guard ("USCG") regulates the navigable waterways through which vessels we own, lease or direct must traverse to supply LNG in Puerto Rico. Our business in Puerto Rico must comply with all applicable Coast Guard regulations. If we are incorrect in our interpretation of applicable requirements, of if there is a change in the interpretation or application of those requirements, the Coast Guard could determine that we have not compiled with applicable requirements, which could lead to fines or restrictions on our operations. For example, on September 26, 2024, we received a letter from the Coast Guard alleging that some aspects of our vessel operations may not comply with all applicable requirements. On October 21, 2024, we filed an appeal with USCG under 33 CFR 160.7. However, 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. There is no assurance that we will obtain and maintain these permits and authorizations on favorable terms, or that we will be able to obtain them on a timely basis, and we may not be able to complete our projects, start or continue our operations, recover our investment in our projects and may be subject to financial penalties or termination under our customer and other agreements, which could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects.

When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project.

A key part of our business strategy is to attract new customers by agreeing to finance and develop new facilities, power plants, liquefaction facilities and related infrastructure in order to win new customer contracts for the supply of natural gas, LNG, steam or power. We intend to employ a similar strategy for our Klondike business. This strategy requires us to invest capital and time to develop a project in exchange for the ability to sell our products and generate fees from customers in the future. When we develop these projects, our required capital expenditure may be significant, and we typically do not generate meaningful fees from customers until the project has commenced commercial operations, which may take a year or more to achieve. If the project is not successfully developed for any reason, we face the risk of not recovering some or all of our invested capital, which may be significant. If the project is successfully developed, we face the risks that our customers may not fulfill their payment obligations or may not fulfill other performance obligations that impact our ability to collect payment. Our customer contracts and development agreements do not fully protect us against this risk and, in some instances, may not provide any meaningful protection from this risk. This risk is heightened in foreign jurisdictions, particularly if our counterparty is a government or government-related entity because any attempt to enforce our contractual or other rights may involve long and costly litigation where the ultimate outcome is uncertain. If we invest capital in a project where we do not receive the payments we expect, we will have less capital to invest in other projects, our liquidity, results of operations and financial condition could be materially and adversely affected, and we could face the inability to comply with the terms of our existing debt or other agreements, which would exacerbate these adverse effects.

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Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations.

We have significant working capital requirements, primarily driven by the time difference between the time when we incur costs to build and/or purchase our Facilities and other projects and the time in which we receive revenues from customers after such Facilities and other projects are complete. We also experience timing date differences between the date we pay for natural gas and the payment dates we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working capital, we may not be able to pursue our growth strategy, respond to competitive pressures or fund key strategic initiatives, such as the development of our facilities, which may harm our business, financial condition and results of operations.

Our ability to generate revenues is substantially dependent on our current and future long-term agreements and the performance by customers under such agreements.

Our business strategy relies upon our ability to successfully market our products to our existing and new customers and enter into or replace our long-term supply and services agreements for the sale of natural gas, LNG, steam and power. If we contract with our customers on short-term contracts, our pricing can be subject to more fluctuations and less favorable terms, and our earnings are likely to become more volatile. An increasing emphasis on the short-term or spot LNG market may in the future require us to enter into contracts based on variable market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in our cash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover our financing costs for related vessels. Our ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. Their obligations may include certain nomination or operational responsibilities, construction or maintenance of their own facilities which are necessary to enable us to deliver and sell natural gas or LNG, and compliance with certain contractual representations and warranties. Further, adverse economic conditions in our industry increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings. For example, JPS and SJPC, which are public utility companies in Jamaica, could be subject to austerity measures imposed on Jamaica by the International Monetary Fund (the “IMF”) and other international lending organizations. Jamaica is currently subject to certain public spending limitations imposed by agreements with the IMF, and any changes under these agreements could limit JPS’s and SJPC’s ability to make payments under their long-term GSAs and, in the case of JPS, its ability to make payments under its PPA, with us. In addition, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under its contracts will be largely dependent upon funding from federal sources. Specifically, PREPA’s contracting practices in connection with restoration and repair of PREPA’s electrical grid in Puerto Rico, and the terms of certain of those contracts, have been subject to comment and are the subject of review and hearings by U.S. federal and Puerto Rican governmental entities. Certain of our subsidiaries are counterparties to contracts with governmental entities, including PREPA. Although these contracts require payment and performance of certain obligations, we remain subject to the statutory limitations on enforcement of those contractual provisions that protect these governmental entities. In the event that PREPA or any applicable governmental counterparty does not have or does not obtain the funds necessary to satisfy their obligations to us under our agreements, or if they terminate our agreements prior to the end of the agreed term, our financial condition, results of operations and cash flows could be materially and adversely affected. If any of these customers fails to perform its obligations under its contract for the reasons listed above or for any other reason, our ability to provide products or services and our ability to collect payment could be negatively impacted, which could materially adversely affect our operating results, cash flow and liquidity, even if we were ultimately successful in seeking damages from such customer for a breach of contract.

Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our results of operations for the year ended December 31, 2024, include our Montego Bay Facility, Old Harbour Facility, San Juan Facility and certain industrial end-users. In addition, we placed a portion of our La Paz Facility into service in the fourth quarter of 2021, and our revenue and results of operations have begun to be impacted by operations in Mexico, including agreements with certain power generation facilities in Baja California Sur. Our results in 2024 exclude other developments, including our Puerto Sandino Facility, the Barcarena Facility, Santa Catarina Facility and Ireland Facility. Jamaica, Mexico and Puerto Rico have historically experienced economic volatility and the general condition and performance of their economies, over which we have no control, may affect our business, financial condition and results of

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operations. Jamaica, Mexico and Puerto Rico are subject to acts of terrorism or sabotage and natural disasters, in particular hurricanes, extreme weather conditions, crime and similar other risks which may negatively impact our operations in the region. See “—Risks Related to the Jurisdictions in Which We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.” We may also be affected by trade restrictions, such as tariffs or other trade controls. Additionally, tourism is a significant driver of economic activity in these geographies and directly and indirectly affects local demand for our LNG and therefore our results of operations. Trends in tourism in these geographies are primarily driven by the economic condition of the tourists’ home country or territory, the condition of their destination, and the availability, affordability and desirability of air travel and cruises. Additionally, unexpected factors could reduce tourism at any time, including local or global economic recessions, terrorism, travel restrictions, pandemics, severe weather or natural disasters. Due to our current lack of asset and geographic diversification, an adverse development at our operating facilities, in the energy industry or in the economic conditions in these geographies, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results.

Our current results of operations and liquidity are, and will continue to be in the near future, substantially dependent upon a limited number of customers, including JPS, SJPC, CFE and PREPA, which have each entered into long-term GSAs and, in the case of JPS, a PPA in relation to the power produced at the CHP Plant, with us, and Jamalco, which has entered into a long-term SSA with us, and which represent a substantial majority of our income. Our operating results are currently contingent on our ability to maintain LNG, natural gas, steam and power sales to these customers. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. The loss of any of these customers or the early termination of any of these contracts could have an adverse effect on our revenues and we may not be able to enter into a replacement agreement on terms as favorable as the terminated agreement. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition.

We may not be able to convert our anticipated customer pipeline into binding long-term contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate.

We are actively pursuing a significant number of new contracts for the sale of LNG, natural gas, steam, and power with multiple counterparties in multiple jurisdictions. Counterparties commemorate their purchasing commitments for these products in various degrees of formality ranging from traditional contracts to less formal arrangements, including non-binding letters of intent, non-binding memorandums of understanding, non-binding term sheets and responses to requests for proposals with potential customers. These agreements and any award following a request for proposals are subject to negotiating final definitive documents. The negotiation process may cause us or our potential counterparty to adjust the material terms of the agreement, including the price, term, schedule and any related development obligations. We cannot assure you if or when we will enter into binding definitive agreements for transactions initially described in non-binding agreements, and the terms of our binding agreements may differ materially from the terms of the related non-binding agreements. In addition, the effectiveness of our binding agreements can be subject to a number of conditions precedent that may not materialize, rendering such agreements non-effective. Moreover, while certain of our long-term contracts contain minimum volume commitments, our expected sales to customers under existing contracts may be substantially in excess of such minimum volume commitments. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to nominate in excess of such minimum quantities and to perform their obligations under their respective contracts. Given the variety of sales processes and counterparty acknowledgments of the volumes they will purchase, we sometimes identify potential sales volumes as being either “Committed” or “In Discussion.” “Committed” volumes generally refer to the volumes that management expects to be sold under binding contracts or awards under requests for proposals. “In Discussion” volumes generally refer to volumes related to potential customers that management is actively negotiating, responding to a request for proposals, or with respect to which management anticipates a request for proposals or competitive bid process to be announced based on discussions with potential customers. Management’s estimations of “Committed” and “In Discussion” volumes may prove to be incorrect. Accordingly, we cannot assure you that “Committed” or “In Discussion” volumes will result in actual sales, and such volumes should not be used to predict the Company’s future results. We may never sign a binding agreement to sell our products to the counterparty, or we may sell much less volume than we estimate, which could result in our inability to generate the revenues and profits we anticipate, having a material adverse effect on our results of operations and financial condition.

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Our contracts with our customers are subject to termination under certain circumstances.

Our contracts with our customers contain various termination rights. For example, each of our long-term customer contracts, including the contracts with JPS, SJPC, Jamalco and PREPA, contain various termination rights allowing our customers to terminate the contract, including, without limitation:

•upon the occurrence of certain events of force majeure;

•if we fail to make available specified scheduled cargo quantities;

•the occurrence of certain uncured payment defaults;

•the occurrence of an insolvency event;

•the occurrence of certain uncured, material breaches; and

In addition, we have short-term customer contracts with renewal rights which the customer may choose not to renew. We may not be able to replace these contracts on desirable terms, or at all, if they are terminated. Contracts that we enter into in the future may contain similar provisions. If any of our current or future contracts are terminated, such termination could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess.

A substantial majority of our revenue is dependent upon our LNG sales to third parties. We operate in the highly competitive industry for LNG and face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies and utilities, in the various markets in which we operate and many of which have been in operation longer than us. Various factors relating to competition may prevent us from entering into new or replacement customer contracts on economically comparable terms to existing customer contracts, or at all, including, among others:

•increases in worldwide LNG production capacity and availability of LNG for market supply;

•increases in demand for natural gas but at levels below those required to maintain current price equilibrium with respect to supply;

•increases in the cost to supply natural gas feedstock to our liquefaction projects;

•increases in the cost to supply LNG feedstock to our facilities;

•decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, HFO and ADO;

•decreases in the price of LNG; and

•displacement of LNG or fossil fuels more broadly by alternate fuels or energy sources or technologies (including but not limited to nuclear, wind, hydrogen,solar, biofuels and batteries) in locations where access to these energy sources is not currently available or prevalent.

In addition, we may not be able to successfully execute on our strategy to supply our existing and future customers with LNG produced primarily at our own liquefaction facilities upon completion of the Pennsylvania Facility or through our Fast LNG solution. Various competitors have and are developing LNG facilities in other markets, which will compete with our LNG facilities, including our Fast LNG solution. Some of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs, larger and more versatile fleets, and substantially greater financial, technical and marketing resources than we currently possess. We also face competition for the contractors needed to build our facilities and skilled employees. See “—We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us.” The superior resources that some of these competitors have available for

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deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects. We anticipate that an increasing number of offshore transportation companies, including many with strong reputations and extensive resources and experience will enter the LNG transportation market and the FSRU market. This increased competition may cause greater price competition for our products. As a result of these factors, we may be unable to expand our relationships with existing customers or to obtain new customers on a favorable basis, if at all, which would have a material adverse effect on our business, results of operations and financial condition.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers.

Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors:

•additions to competitive regasification capacity in North America, Brazil, Europe, Asia and other markets, which could divert LNG or natural gas from our business;

•imposition of tariffs by China or any other jurisdiction on imports of LNG from the United States;

•insufficient or oversupply of natural gas liquefaction or export capacity worldwide;

•insufficient LNG tanker capacity;

•weather conditions and natural disasters;

•reduced demand and lower prices for natural gas;

•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities, including shut-ins and possible proration, which may decrease the production of natural gas;

•cost improvements that allow competitors to offer LNG regasification services at reduced prices;

•changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

•changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

•political conditions in natural gas producing regions;

•adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and

•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

Adverse trends or developments affecting any of these factors, including the timing of the impact of these factors in relation to our purchases and sales of natural gas and LNG could result in increases in the prices we have to pay for natural gas or LNG, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. Certain actions by the Organization of Petroleum Exporting Countries ("OPEC") related to the supply of oil in the market have caused volatility and disruption in the price of oil which may negatively impact our potential customers’ willingness or ability to enter into new contracts for the purchase of natural gas. Additionally, in situations where our supply chain has capacity constraints and as a result we are unable to receive all volumes under our long-term LNG supply agreements, our supplier may sell volumes of LNG in a mitigation sale to third parties. In these cases, the factors above may impact the

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price and amount we receive under mitigation sales and we may incur losses that would have an adverse impact on our financial condition, results of operations and cash flows. Conversely, as in recent years, market conditions may increase LNG values to historically high levels. These elevated market values increase the economic incentives an LNG seller has to fail to deliver LNG cargos to us if they can sell the same LNG cargos at a higher price to another buyer in the market after giving effect to any contractual penalties the seller would owe to us for failing to deliver. Our contracts may not require an LNG seller to compensate us for the full current market value of an LNG cargo that we have purchased, and if so, we may not be contractually entitled to receive full economic indemnification upon an LNG seller’s failure to deliver an LNG cargo to us. Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amount of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no assurance we will achieve our target cost or pricing goals. In particular, because we have not currently procured fixed-price, long-term LNG supply to meet all future customer demand, increases in LNG prices and/or shortages of LNG supply could adversely affect our profitability. Our actual costs and any profit realized on the sale of our LNG may vary from the estimated amounts on which our contracts for feedgas were originally based. There is inherent risk in the estimation process, including significant changes in the demand for and price of LNG as a result of the factors listed above, many of which are outside of our control. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported on or to our tankers and facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.

Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses.

Our strategy is to maintain a manageable balance between LNG purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the LNG purchased by selling LNG for physical delivery to third-party users, such as public utilities, shipping/marine cargo companies, industrial users, railroads, trucking fleets and other potential end-users converting from traditional ADO or oil fuel to natural gas. These strategies cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated supply chain could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when LNG is purchased against one pricing index and sold against a different index. Moreover, we are also exposed to other risks, including price risks on LNG we own, which must be maintained in order to facilitate transportation of the LNG to our customers or to our facilities. If we were to incur a material loss related to commodity price risks, it could have a material adverse effect on our financial position, results of operations and cash flows.

Any use of hedging arrangements may adversely affect our future operating results or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter (“OTC”) options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when expected supply is less than the amount hedged, the counterparty to the hedging contract defaults on its contractual obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

We are dependent on third-party LNG suppliers and the development of our own portfolio is subject to various risks and assumptions.

Under our GSAs, PPAs, capacity reservation agreements and SSAs, we are required to deliver to our customers specified amounts of LNG, natural gas, power and steam, respectively, at specified times and within certain specifications, all of which requires us to obtain sufficient amounts of LNG from third-party LNG suppliers or our own portfolio. We may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may provide a counterparty with the right to terminate its GSA, PPA, capacity reservation agreement or SSA, as applicable, or subject us to remedial obligations under those agreements. While we have entered into supply agreements for the purchase of LNG between 2024 and 2047, we may need to purchase significant additional LNG volumes to meet our

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delivery obligations to our downstream customers. Price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items or to sell our inventory of natural gas or LNG at attractive prices. Failure to secure contracts for the purchase of a sufficient amount of LNG or at favorable prices could materially and adversely affect our business, operating results, cash flows and liquidity.

The development of our own portfolio of LNG is subject to various risks and assumptions. In particular, the estimation of proved gas reserves involves subjective judgements and determinations based on available geological, technical, contractual, and economic information. Estimates can change over time because of new information from production or drilling activities, changes in economic factors, such as oil and gas prices, alterations in the regulatory policies of host governments, or other events. Estimates also change to reflect acquisitions, divestments, new discoveries, extensions of existing fields and mines, and improved recovery techniques. Published proved gas reserves estimates could also be subject to correction because of errors in the application of rules and changes in guidance. Downward adjustments could indicate lower future production volumes and could also lead to impairment of assets. This could have a material adverse effect on our business, operating results, cash flows and liquidity.

Additionally, we are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to replace such contracts or purchase LNG on the spot market or receive a sufficient quantity of LNG in order to satisfy our delivery obligations under our GSAs, PPAs, capacity reservation agreements and SSAs or at favorable terms. Under tanker charters, we are obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased, as our vessels may be too small for those obligations. Any such failure to purchase or receive delivery of LNG or natural gas in sufficient quantities could result in our failure to satisfy our obligations to our customers, which could lead to losses, penalties, indemnification and potentially a termination of agreements with our customers. Furthermore, we may seek to litigate any such breaches by our third-party LNG suppliers and shippers. Such legal proceedings may involve claims for substantial amounts of money and we may not be successful in pursing such claims. Even if we are successful, any litigation may be costly and time-consuming. If any such proceedings were to result in an unfavorable outcome, we may not be able to recover our losses (including lost profits) or any damages sustained from our agreements with our customers. See “—General Risks—We are and may be involved in legal proceedings and may experience unfavorable outcomes.” These actions could also expose us to adverse publicity, which might adversely affect our reputation and therefore, our results of operations. Further, it could have an adverse effect on our business, operating results, cash flows and liquidity, which could in turn materially and adversely affect our liquidity to make payments on our debt or comply with our financial ratios and other covenants. See “—We have incurred, and may in the future incur, a significant amount of debt.”

LNG that is processed, transported and/or stored on FSRUs and transported via pipeline is subject to risk of loss or damage.

LNG processed, transported and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, cargo ageing or otherwise. Where we have chartered in, but subsequently not outchartered an FSRU, which in turn results in our being unable to transfer risk of loss or damage, we could bear the risk of loss or damage to all those volumes of LNG for the period of time during which those applicable volumes of LNG are stored on an FSRU or are dispatched to a pipeline. Any such disruption to the supply of LNG and natural gas may lead to delays, disruptions or curtailments in the production of power at our facilities, which could materially and adversely affect our revenues, financial condition and results of operations.

We rely on tankers and other vessels outside of our fleet for our LNG transportation and transfer.

In addition to our own fleet of vessels, we rely on third-party ocean-going tankers and freight carriers (for ISO containers) for the transportation of LNG and use ship-to-ship kits to transfer LNG between ships. We may not be able to successfully enter into contracts or renew existing contracts to charter tankers on favorable terms or at all, which may result in us not being able to meet our obligations. Our ability to enter into contracts or renew existing contracts will depend on prevailing market conditions upon expiration of the contracts governing the leasing or charter of the applicable assets. Therefore, we may be exposed to increased volatility in terms of charter rates and contract provisions. Fluctuations in charter rates result from changes in the supply of LNG tankers and demand for capacity and changes in the demand for seaborne carriage of commodities. Because the factors affecting the supply and demand are outside of our control and are highly unpredictable, the nature, timing, direction and degree of changes in industry conditions are also unpredictable. Likewise, our counterparties may seek to terminate or renegotiate their charters or leases with us. If we are not able to

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renew or obtain new charters or leases in direct continuation, or if new charters or leases are entered into at rates substantially above the existing rates or on terms otherwise less favorable compared to existing contractual terms, our business, prospects, financial condition, results of operations and cash flows could be materially adversely affected.

Furthermore, our ability to provide services to our customers could be adversely impacted by shifts in tanker market dynamics, shortages in available cargo carrying capacity, changes in policies and practices such as scheduling, pricing, routes of service and frequency of service, or increases in the cost of fuel, taxes and labor, emissions standards, maritime regulatory changes, sanctions and other factors not within our control. The availability of the tankers could be delayed to the detriment of our LNG business and our customers because the construction and delivery of LNG tankers require significant capital and long construction lead times. Changes in ocean freight capacity, which are outside our control, could negatively impact our ability to provide natural gas if LNG shipping capacity is adversely impacted and LNG transportation costs increase because we may bear the risk of such increases and may not be able to pass these increases on to our customers.

The operation of ocean-going tankers and kits carries inherent risks. These risks include the possibility of natural disasters; mechanical failures; grounding, fire, explosions and collisions; piracy; human error; epidemics; and war and terrorism. We do not currently maintain a redundant supply of ships, ship-to-ship kits or other equipment. As a result, if our current equipment fails, is unavailable or insufficient to service our LNG purchases, production, or delivery commitments we may need to procure new equipment, which may not be readily available or be expensive to obtain. Any such occurrence could delay the start of operations of facilities we intend to commission, interrupt our existing operations and increase our operating costs. Any of these results could have a material adverse effect on our business, financial condition and operating results.

Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when we are seeking a new charter, our earnings may decline.

Hire rates for FSRUs and LNG carriers fluctuate over time as a result of changes in the supply-demand balance relating to the market requirements for FSRUs and LNG carries and future FSRU and LNG carrier capacity. This supply-demand relationship largely depends on a number of factors outside of our control. For example, driven in part by an increase in LNG production capacity, the market supply particularly of LNG carriers has been increasing. We believe that this and any future expansion of the global LNG carrier fleet may have a negative impact on charter hire rates, vessel utilization and vessel values, the impact of which could be amplified if the expansion of LNG production capacity does not keep pace with fleet growth. The LNG market is also closely connected to world natural gas and LNG prices and energy markets, which it cannot predict. A substantial or extended decline in demand for natural gas or LNG could adversely affect our ability to charter or re-charter our vessels at acceptable rates or to acquire and profitably operate new vessels. Accordingly, this could have a material adverse effect on our earnings, financial condition, operating results and prospects.

We may not be able to fully utilize the capacity of our FSRUs and other facilities.

Our FSRU facilities have excess capacity that is currently not dedicated to a particular anchor customer. Part of our business strategy is to utilize undedicated excess capacity of our FSRU facilities to serve additional downstream customers in the regions in which we operate. However, we have not secured, and we may be unable to secure, commitments for all of our excess capacity. Factors which could cause us to contract less than full capacity include difficulties in negotiations with potential counterparties, timing of start-up of new third party projects and factors outside of our control such as the price of and demand for LNG for a particular project. Failure to secure commitments for less than full capacity could impact our future revenues and materially adversely affect our business, financial condition and operating results.

The operation of our vessels is dependent on our ability to deploy our vessels to an NFE terminal or to long-term charters.

Our principal strategy for our FSRU and LNG carriers is to provide steady and reliable shipping, regasification and offshore operations to NFE terminals and, to the extent favorable to our business, replace or enter into new long-term carrier time charters for our vessels. For new LNG projects, LNG ships continue to be provided on a long-term basis, though the level of spot voyages and short-term time charters of less than 12 months in duration together with medium term charters of up to five years has increased in recent years. This trend is expected to continue as the spot market for LNG expands and becomes more liquid. More frequent changes to vessel sizes, propulsion technology and emissions profile, retirements of older vessels, together with an increasing desire by charterers to access modern tonnage could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period. As a result, the

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duration of long-term charters could also decrease over time. We may also face increased difficulty entering into long-term time charters upon the expiration or early termination of our contracts. The process of obtaining long-term charters for FSRUs and LNG carriers is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. If we lose any of our charterers and are unable to re-deploy the related vessel to a NFE terminal or into a new replacement contract for an extended period of time, we will not receive any revenues from the deliveries from that vessel, but we will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition.

Vessel values may fluctuate substantially and, if these values are lower at a time when we are attempting to dispose of vessels, we may incur a loss.

Vessel values can fluctuate substantially over time due to a number of different factors, including:

•prevailing economic conditions in the natural gas and energy markets;

•a substantial or extended decline in demand for LNG;

•increases in the supply of vessel capacity without a commensurate increase in demand;

•the size, tank type and age of a vessel; and

•the cost of retrofitting, steel prices or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.

As our owned or chartered vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on our business and operations if we do not maintain sufficient cash reserves for maintenance and replacement capital expenditures. Moreover, the cost of a replacement vessel could be significant and subject to market pricing.

During the period a vessel is subject to a charter, we will not be permitted to sell it to take advantage of increases in vessel values without the charterers’ consent. If a charter terminates, we may be unable to re-deploy the affected vessels at market rates or for our operations and, rather than continue to incur costs to maintain and finance them, we may seek to dispose of them. When vessel values are low, we may not be able to dispose of vessels at a reasonable price when we wish to sell vessels, and conversely, when vessel values are elevated, we may not be able to acquire additional vessels at attractive prices when we wish to acquire additional vessels, which could adversely affect our business, results of operations, cash flow, and financial condition.

The carrying values of our vessels may not represent their fair market value at any point in time because the market prices of secondhand vessels tend to fluctuate with changes in charter rates, vessel availability and the cost of new build vessels, steel prices and foreign exchange rates. Our vessels are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. We recognized an impairment charge on one of our vessels for the year ended December 31, 2023 and we cannot assure you that we will not recognize impairment losses on our vessels in future years. Any impairment charges incurred as a result of declines in charter rates could negatively affect our business, financial condition, or operating results.

Maritime claimants could arrest our vessels, which could interrupt our cash flow.

If we are in default on certain kinds of obligations related to our vessels, such as those to our lenders, crew members, suppliers of goods and services to our vessels or shippers of cargo, these parties may be entitled to a maritime lien against one or more of our vessels. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in our fleet for claims relating to another of our vessels. The arrest or attachment of one or more of our vessels could interrupt our cash flow and require us to pay to have the arrest lifted. Under some of our present charters, if the vessel is arrested or

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detained (for as few as 14 days in the case of one of our charters) as a result of a claim against us, we may be in default of our charter and the charterer may terminate the charter. This would negatively impact our revenues and cash flows.

We seek to develop innovative and new technologies as part of our strategy that are not yet proven and may not realize the time and cost savings we expect to achieve.

We analyze and seek to implement innovative and new technologies that complement our businesses to reduce our costs, achieve efficiencies for our business and our customers and advance our long-term goals, such as our ISO container distribution system, our Fast LNG solution and our green hydrogen project. The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants. See “—Our Fast LNG technology is not yet proven and we may not be able to implement it as planned or at all.” We are also making investments to develop green hydrogen energy technologies as part of our long-term goal to become one of the world’s leading providers of carbon-free energy. We continue to develop our ISO container distribution systems in the various markets where we operate. We expect to make additional investments in this field in the future. Because these technologies are innovative, we may be making investments in unproven business strategies and technologies with which we have limited or no prior development or operating experience. As an investor in these technologies, it is also possible that we could be exposed to claims and liabilities, expenses, regulatory challenges and other risks. We may not be able to successfully develop these technologies, and even if we succeed, we may ultimately not be able to realize the time, revenues and cost savings we currently expect to achieve from these strategies, which could adversely affect our financial results.

Technological innovation may impair the economic attractiveness of our projects.

The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although we plan to build out our delivery logistics chain in Northern Pennsylvania using proven technologies, we do not have any exclusive rights to any of these technologies. In addition, such technologies may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others, which could materially and adversely affect our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

Our Fast LNG technology is not yet proven and we may not be able to implement it as planned or at all.

We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants. Our ability to create and maintain a competitive position in the natural gas liquefaction industry may be adversely affected by our inability to effectively implement our Fast LNG technology. We have commenced operations at our first Fast LNG solution, but we have not yet supplied any LNG from that facility to customers, and are therefore subject to risks related to full commercial development of the facility. We are also developing our first onshore LNG facility and are therefore subject to construction risks, risks associated with third-party contracting (including the risk that we will not be able to execute contracts with third parties that are necessary to develop the project) and service providers, permitting and regulatory risks. See “—We are subject to various construction risks” and “—We depend on third-party contractors, operators and suppliers.” Because our Fast LNG technology has not been previously implemented, tested or proven, we are also exposed to unknown and unforeseen risks associated with the development of new technologies, including failure to meet design, engineering, or performance specifications, incompatibility of systems, inability to contract or employ third parties with sufficient experience in technologies used or inability by contractors to perform their work, delays and schedule changes, high costs and expenses that may be subject to increase or difficult to anticipate, regulatory and legal challenges, instability or clarity of application of laws, rules and regulations to the technology, and added difficulties in obtaining or securing required permits or authorizations, among others. For example, in April 2024, we experienced an incident involving equipment failure during the commissioning of our Fast LNG project in Altamira, Mexico, which delayed our commencement of operations and resulted in increased costs and delay of commencement of revenue generating activity. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.” The success and profitability of our Fast LNG technology is also dependent on the volatility of the price of natural gas and LNG compared to the related levels of capital spending required to implement the technology. Natural gas and LNG prices have at various times been and may become volatile due to one or more factors. Volatility or weakness in natural gas or LNG prices could render our LNG procured through Fast LNG too expensive for our customers, and we may not be able to obtain our anticipated return on our investment or make our technology profitable. In addition, we may seek to construct and develop

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floating offshore liquefaction units as part of our Fast LNG in jurisdictions which could potentially expose us to increased political, economic, social and legal instability, a lack of regulatory clarity of application of laws, rules and regulations to our technology, or additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. See “—Risks Related to the Jurisdictions in Which We Operate—We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.” Furthermore, as part of our business strategy for Fast LNG, we may enter into tolling agreements with third parties, including in developing countries, and these counterparties may have greater credit risk than typical. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance. We may not be able to successfully develop, construct and implement our Fast LNG solution, and even if we succeed in developing and constructing the technology, we may ultimately not be able to realize the cost savings and revenues we currently expect to achieve from it, which could result in a material adverse effect upon our operations and business.

Our data center infrastructure business has no operating history, and we may not recognize revenue or operating income in the future.

On July 2, 2024, we announced the launch of Klondike Digital Infrastructure, a power and data center infrastructure business. We are subject to a multitude of risks inherent in a recently established business venture in a rapidly developing and changing industry. We have no operating history in the data center infrastructure business and may not be able to achieve our business objectives. We cannot assure you that our past experience will be sufficient to allow us to successfully achieve our business objectives, and our past performance should not be used as an indicator of our likely performance. Our lack of operating history in the data center infrastructure business, particularly in the development and operation of data center infrastructure, also makes it difficult to evaluate the prospects of this business. We have not yet been able to confirm that our business model can or will be successful, and we may not ever recognize revenue or operating income from this business. Our expectations regarding the data center business may not prove to be accurate. Our operating results will likely fluctuate moving forward as we develop this business. In addition, we expect additional growth in this business, which could place significant demands on our management team and other resources and require us to continue developing and improving our operational, financial and other internal controls. We may not be able to address these challenges in a cost-effective manner or at all. If we do not effectively manage our growth, we may not be able to execute on our business plan, respond to competitive pressures or take advantage of market opportunities, and our business, financial condition and results of operations could be materially harmed.

We do not currently generate cash from operations from this new business line, so we will need additional funding from other sources to develop this business. There can be no assurance that we will be able to obtain financing on favorable terms or at all, or that we will have sufficient capital to fully implement our business plan, which could have a material adverse effect on this business, results of operations, financial condition and prospects. You should consider our data center business and prospects in light of these risks and the risks and difficulties that we will encounter as we continue to develop our business model. We may not be able to address these risks and difficulties successfully, which would materially harm our business and operating results.

Our data center business strategy depends on the successful development of our projects and any delays or unexpected costs associated with such projects may harm our growth prospects, future operating results and financial condition.

We intend to develop a geographically diverse portfolio of power and data center infrastructure and we have more than 1,000 acres of developable land across sites in Brazil, Ireland, and the United States that we are analyzing for potential use in the business. Our business strategy depends upon the successful acquisition, permitting, gas supply, transmission work and completion of the development of these sites and similar projects in the future. Current and future development projects and expansion into new markets will involve substantial planning, allocation of significant company resources and certain risks, including risks related to the acquisition of real property, financing, zoning, permits and other regulatory approvals, construction costs and delays.

These development projects will also require us to carefully select and rely on the experience of one or more general contractors and associated subcontractors during the construction process. Should a general contractor or significant subcontractor experience financial or other problems during the construction process, we could experience significant delays, increased costs to complete the project and other negative impacts to our expected financial returns. Site selection in current and expansion markets is also a critical factor in our expansion plans, and there may not be suitable properties available in our markets at a location that is attractive to our customers and has the necessary combination of other characteristics. Furthermore, while we may prefer to locate new data centers adjacent to or in close proximity to our existing data centers, we may be limited by the size and location of suitable properties. If we are unable to successfully

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develop and operate data center properties, our business, financial condition and results of operations will be significantly impaired.

Our data center business model depends upon the demand for data centers.

We intend to be in the business of developing infrastructure to serve data centers. A reduction in the demand for data center power or connectivity would have an adverse effect on our ability to develop our data center infrastructure business. We are susceptible to general economic slowdowns as well as adverse developments in the data center, internet and data communications and broader technology industries. Any such slowdown or adverse development could lead to reduced corporate information technology (“IT”) spending or reduced demand for data center space. Reduced demand could also result from business relocations, including to markets that we do not currently serve. Changes in industry practice or in technology could also reduce demand for the physical data center space we will provide. Our results of operations and financial condition could be materially adversely affected as a result of any or all of these factors.

We have incurred, and may in the future incur, a significant amount of debt. The agreements governing our significant indebtedness place restrictions on us and our subsidiaries, reducing operational and financing flexibility and creating default risks.

On an ongoing basis, we engage with lenders and other financial institutions in an effort to improve our liquidity and capital resources. As of December 31, 2024, we had approximately $9,027.1 million aggregate principal amount of indebtedness outstanding on a consolidated basis (which does not include any unconsolidated debt). The terms and conditions of our indebtedness, including the2026 Notes Indenture, the 2029 Notes Indenture, the Intercompany Credit Agreements and the Existing Credit Agreements (each as defined in "Management's Discussion and Analysis of Financial Condition and Results of Operations-Recent Developments."), include restrictive covenants that may limit our ability to operate our business, to incur or refinance our debt, pay dividends or make distributions or make certain other restricted payments, create liens on our or our subsidiaries' assets, sell or otherwise dispose of assets, 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. If we fail to comply with any of these restrictions or are unable to pay our debt service when due, our debt could be accelerated or cross-accelerated, and we cannot assure you that we will have the ability to repay such accelerated debt. Any such default could also have adverse consequences to our status and reporting requirements, reducing our ability to quickly access the capital markets. Additionally, our Existing Credit Agreements and the intercompany loan agreements securing, directly or indirectly, the New 2029 Notes require proceeds of certain asset sales be used to pay down existing indebtedness, which may further limit our ability to operate our business and finance future operations and capital needs.

Our ability to service our existing and any future debt will depend on our performance and operations, which is subject to factors that are beyond our control and compliance with covenants in the agreements governing such debt. We may be unable to maintain a level of cash flows from operating activities sufficient to permit us to fund our day-to-day operations or to pay the principal, premium, if any, and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations and other cash requirements, we could face substantial liquidity problems and could be forced to reduce or delay investments and capital expenditures or to sell assets or operations, seek additional capital or restructure or refinance our operations or indebtedness. If we cannot make scheduled payments on our debt, we will be in default and, as a result, lenders under and holder of any of our existing and future indebtedness could declare all outstanding principal and interest to be due and payable, the lenders under our debt instruments could terminate their commitments to loan money, our secured lenders could foreclose against the assets securing such borrowings and we could be forced into bankruptcy or liquidation. We may also incur additional debt to fund our business and strategic initiatives. If we incur additional debt and other obligations, the risks associated with our substantial leverage and the ability to service such debt would increase, which could have a material adverse effect on our business, results of operation and financial condition.

Despite our substantial level of indebtedness, we and our subsidiaries will be permitted to incur additional indebtedness in the future. This could further exacerbate the risks associated with our substantial indebtedness.

In addition, as our existing indebtedness matures, we may need to refinance that indebtedness with new indebtedness that may have a higher interest rate, which will increase our fixed costs. Although the instruments governing our indebtedness contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and the indebtedness incurred in compliance with these restrictions could be substantial. If

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we incur additional debt and other obligations, the risks associated with our substantial leverage and the ability to service such debt would increase, which could have a material adverse effect on our business, results of operation and financial condition. For example, the New 2029 Notes issued pursuant to the New 2029 Indenture, issued in part to refinance our 2025 Notes, 2026 Notes and 2029 Notes in part to provide additional liquidity to the business, bear interest at a rate of 12.000% per annum, representing a signficiant increasing our annual interest expense, while also increasing our total aggregate principal amount of indebtedness outstanding. For additional detail, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments”- and "Liquidity and Capital Resources-Long Term Debt and Preferred Stock."

Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms.

We believe we will have sufficient liquidity, cash flow from operations and access to additional capital sources to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. In the future, we expect to incur additional indebtedness to assist us in developing our operations and we are considering alternative financing options, including in Brazil and other specific markets or the opportunistic sale of one of our non-core assets such as the sale of our assets in Jamaica. We also historically have relied, and in the future will likely rely, on borrowings under term loans and other debt instruments to fund our capital expenditures. If any of the lenders in the syndicates backing these debt instruments were unable to perform on its commitments, we may need to seek replacement financing. We cannot assure you that such additional funding will be available on acceptable terms, or at all. Our ability to raise additional capital on acceptable terms will depend on financial, economic and market conditions, which have increased in volatility and at times have been negatively impacted due to our progress in executing our business strategy and other factors, many of which are beyond our control, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector. The terms of the Notes financing subjected us to, and additional debt financing, if available, may subject us to increased restrictive covenants that could limit, and in the case of the former, significantly limit, our flexibility to incur additional indebtedness and conduct future business activities and could result in us expending significant resources to service our obligations. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the requirements of our existing financing and availability of such additional funding. If we are unable to obtain additional funding, approvals or amendments to our financings outstanding from time to time, or if additional funding is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan, we may be unable to pay or refinance our indebtedness or to fund our other liquidity needs, and our financial condition or results of operations may be materially adversely affected.

We have entered into, and may in the future enter into or modify existing, joint ventures that might restrict our operational and corporate flexibility or require credit support.

We have entered into, and may in the future enter, into joint venture arrangements with third parties in respect of our projects and assets. For example, in August 2022, we established Energos, as a joint venture platform with certain funds or investment vehicles managed by Apollo, for the development of a global marine infrastructure platform, of which we owned 20% prior to our sale of approximately all of our 20% stake in February 2024. As we do not operate the assets owned by these joint ventures, our control over their operations is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint ventures. Because we do not control all of the decisions of our joint ventures, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in its or the joint venture’s best interests. For example, we cannot unilaterally cause the distribution of cash by our joint ventures. Additionally, as the joint ventures are separate legal entities, any right we may have to receive assets of any joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the creditors of that joint venture (including tax authorities, trade creditors and any other third parties that require such subordination, such as lenders and other creditors). Moreover, joint venture arrangements involve various risks and uncertainties, such as our commitment to fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not satisfy their financial obligations to the joint venture. We have provided and may in the future provide guarantees or other forms of credit support to our joint ventures and/or affiliates. Failure by any of our joint ventures, equity method investees and/or affiliates to service their debt requirements and comply with any provisions contained in their commercial loan agreements, including paying scheduled installments and complying with certain covenants, may lead to an event of default under the related loan agreement. As a result, if our joint ventures, equity method investees and/or affiliates are unable to obtain a waiver or do not have enough cash on hand to

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repay the outstanding borrowings, the relevant lenders may foreclose their liens on the relevant assets or vessels securing the loans or seek repayment of the loan from us, or both. Either of these possibilities could have a material adverse effect on our business. Further, by virtue of our guarantees with respect to our joint ventures and/or affiliates, this may reduce our ability to gain future credit from certain lenders.

The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

We have entered and may in the future enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or OTC options and swaps with other natural gas merchants and financial institutions. Title VII of the Dodd-Frank Act established federal regulation of the OTC derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other federal regulators may adversely affect the cost and availability of the swaps that we may use for hedging, including, without limitation, rules setting limits on the positions in certain contracts, rules regarding aggregation of positions, requirements to clear through specific derivatives clearing organizations and trading platforms, requirements for posting of margins, regulatory requirements on swaps market participants. Our counterparties that are also subject to the capital requirements set out by the Basel Committee on Banking Supervision in 2011, commonly referred to as “Basel III,” may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets. Our subsidiaries and affiliates operating in Europe and the Caribbean may be subject to the European Market Infrastructure Regulation (“EMIR”) and the Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”) as wholesale energy market participants, which may impose increased regulatory obligations, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data, as well as requiring liquid collateral. These regulations could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, and reduce our ability to monetize or restructure derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to forgo the use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

We may incur impairments to long-lived assets.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, decline of our market capitalization, reduced estimates of future cash flows for our business segments or disruptions to our business, or adverse actions by governmental entities, changes to regulation or legislation have in the past and could in the future lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.

Weather events or other natural or manmade disasters or phenomena, some of which may be adversely impacted by global climate change, could have a material adverse effect on our operations and projects, as well as on the economies in the markets in which we operate or plan to operate.

Weather events such as storms and related storm activity and collateral effects, or other disasters, accidents, catastrophes or similar events, natural or manmade, such as explosions, fires, seismic events, floods or accidents, could result in damage to our facilities, liquefaction facilities, or related infrastructure, interruption of our operations or our supply chain, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our onshore and offshore operations. Due to the nature of our operations, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects, in particular with respect to fleet operations, floating offshore

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liquefaction units and other infrastructure we may develop in connection with our Fast LNG technology. In particular, we may seek to construct and develop floating offshore liquefaction units as part of our Fast LNG in locations that are subject to risks posed by hurricanes and similar severe weather conditions or natural disasters or other adverse events or conditions that could severely affect our infrastructure, resulting in damage or loss, contamination to the areas, and suspension of our operations. For example, our operations in coastal regions in southern Florida, the Caribbean, the Gulf of Mexico and Latin America are frequently exposed to natural hazards such as sea-level rise, coastal flooding, cyclones, extreme heat, hurricanes, and earthquakes. These climate risks can affect our operations, potentially even damaging or destroying our facilities, leading to production downgrades, costly delays, reduction in workforce productivity, and potential injury to our people. In addition, jurisdictions with increased political, economic, social and legal instability, lack of regulatory clarity of application of laws, rules and regulations to our technology, and could potentially expose us to additional jurisdictional risks related to currency exchange, tariffs and other taxes, changes in laws, civil unrest, and similar risks. In addition, because of the location of some of our operations, we are subject to other natural phenomena, including earthquakes, such as the one that occurred near Puerto Rico in January 2020, which resulted in a temporary delay of development of our Puerto Rico projects, hurricanes and tropical storms. If one or more tankers, pipelines, facilities, liquefaction facilities, vessels, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our facilities, liquefaction facilities, and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe or similar event, our construction projects and our operations could be significantly interrupted, damaged or destroyed. These delays, interruptions and damages could involve substantial damage to people, property or the environment, and repairs could take a significant amount of time, particularly in the event of a major interruption or substantial damage. We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” The occurrence of a significant event, or the threat thereof, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Existing and future environmental, social, health and safety laws and regulations could result in increased or more stringent compliance requirements, which may be difficult to comply with or result in additional costs and may otherwise lead to significant liabilities and reputational damage.

Our business is now and will in the future be subject to extensive national, federal, state, municipal and local laws, rules and regulations, in the United States and in the jurisdictions where we operate, relating to the environment, social, health and safety and hazardous substances. These requirements regulate and restrict, among other things: the siting and design of our facilities; discharges to air, land and water, with particular respect to the protection of human health, the environment and natural resources and safety from risks associated with storing, receiving and transporting LNG, natural gas and other substances; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA and the CWA, and analogous laws and regulations in the jurisdictions in which we operate, restrict or prohibit the types, quantities and concentrations of substances that can be emitted into the environment in connection with the construction and operation of our facilities and vessels, and require us to obtain and maintain permits and provide governmental authorities with access to our facilities and vessels for inspection and reports related to our compliance. For example, the Pennsylvania Department of Environmental Protection laws and regulations will apply to the construction and operation of the Pennsylvania Facility. Changes or new environmental, social, health and safety laws and regulations could cause additional expenditures, restrictions and delays in our business and operations, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. For example, in October 2017, the U.S. Government Accountability Office issued a legal determination that a 2013 interagency guidance document was a “rule” subject to the Congressional Review Act (“CRA”). This legal determination could open a broader set of agency guidance documents to potential disapproval and invalidation under the CRA, potentially increasing the likelihood that laws and regulations applicable to our business will become subject to revised interpretations in the future that we cannot predict. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Any failure in environmental, social, health and safety performance from our operations may result in an event that causes personal harm or injury to our employees, other persons, and/or the environment, as well as the imposition of injunctive relief and/or penalties or fines for non-compliance with relevant regulatory requirements or litigation. Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG liquefaction, storage, transportation or regasification operations), could generate public concern, which may lead to new laws and/or regulations that would impose more stringent requirements on our operations, have a corresponding impact on our ability to obtain

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permits and approvals, and otherwise jeopardize our reputation or the reputation of our industry as well as our relationships with relevant regulatory agencies and local communities. As the owner and operator of our facilities and owner or charterer of our vessels, we may be liable, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment at or from our facilities and for any resulting damage to natural resources, which could result in substantial liabilities, fines and penalties, capital expenditures related to cleanup efforts and pollution control equipment, and restrictions or curtailment of our operations. Any such liabilities, fines and penalties could exceed the limits of our insurance coverage. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets.

Greenhouse Gases/Climate Change. The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state government levels to monitor and limit existing and future GHG emissions. As a result, our operations are subject to a series of risks associated with the processing, transportation, and use of fossil fuels and emission of GHGs. In the United States to date, no comprehensive climate change legislation has been implemented at the federal level, although various individual states and state coalitions have adopted or considered adopting legislation, regulations or other regulatory initiatives, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and emission restrictions, pollution reduction incentives, or renewable energy or low-carbon replacement fuel quotas. At the international level, the United Nations-sponsored “Paris Agreement” was signed by 197 countries who agreed to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. On January 20, 2025, President Trump signed an executive order announcing the withdrawal of the United States from the Paris Agreement. Though most other countries (including those where we operate or plan to operate) have signed or acceded to this agreement. The scope of future climate and GHG emissions-focused regulatory requirements, if any, remains uncertain. Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political uncertainty in the United States and worldwide. For example, based in part on the publicized climate plan and pledges by the U.S. government, there may be significant legislation, rulemaking, or executive orders that seek to address climate change, incentivize low-carbon infrastructure or initiatives, or ban or restrict the exploration and production of fossil fuels. Executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve U.S. goals under the Paris Agreement. President Trump, however, has generally expressed opposition to regulatory initiatives aimed at restricting oil and gas operations and the impact his administration will have on any of these initiatives cannot be predicted.

Climate-related litigation and permitting risks are also increasing, as a number of cities, local governments and private organizations have sought to either bring suit against oil and natural gas companies in state or federal court, alleging various public nuisance claims, or seek to challenge permits required for infrastructure development. Fossil fuel producers are also facing general risks of shifting capital availability due to stockholder concern over climate change and potentially stranded assets in the event of future, comprehensive climate and GHG-related regulation. While several of these cases have been dismissed, there is no guarantee how future lawsuits might be resolved.

The adoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on GHG emissions could result in increased compliance costs, and thereby reduce demand for or erode value for, the natural gas that we process and market. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases in customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHGs, or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. Furthermore, political, litigation, and financial risks may result in reduced natural gas production activities, increased liability for infrastructure damages as a result of climatic changes, or an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

Fossil Fuels. Our business activities depend upon a sufficient and reliable supply of natural gas feedstock, and are therefore subject to concerns in certain sectors of the public about the exploration, production and transportation of natural gas and other fossil fuels and the consumption of fossil fuels more generally. For example, PHMSA has promulgated detailed regulations governing LNG facilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security.None of our LNG facilities currently under development are subject to PHMSA’s jurisdiction, but regulators and governmental agencies in the other

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jurisdictions in which we operate can impose similar siting, design, construction and operational requirements that can affect our projects, facilities, infrastructure and operations. Legislative and regulatory action, and possible litigation, in response to such public concerns may also adversely affect our operations. We may be subject to future laws, regulations, or actions to address such public concern with fossil fuel generation, distribution and combustion, greenhouse gases and the effects of global climate change. Our customers may also move away from using fossil fuels such as LNG for their power generation needs for reputational or perceived risk-related reasons. These matters represent uncertainties in the operation and management of our business, and could have a material adverse effect on our financial position, results of operations and cash flows.

Hydraulic Fracturing. Certain of our suppliers of natural gas and LNG employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations (including shale formations), which currently entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Moreover, hydraulically fractured natural gas wells account for a significant percentage of the natural gas production in the U.S.; the U.S. Energy Information Administration reported in 2016 that hydraulically fractured wells provided two-thirds of U.S. marketed gas production in 2015. Hydraulic fracturing activities can be regulated at the national, federal or local levels, with governmental agencies asserting authority over certain hydraulic fracturing activities and equipment used in the production, transmission and distribution of oil and natural gas, including such oil and natural gas produced via hydraulic fracturing. Such authorities may seek to further regulate or even ban such activities. For example, the Delaware River Basin Commission (“DRBC”), a regional body created via interstate compact responsible for, among other things, water quality protection, water supply allocation, regulatory review, water conservation initiatives, and watershed planning in the Delaware River Basin, has implemented a de facto ban on hydraulic fracturing activities in that basin since 2010 pending the approval of new regulations governing natural gas production activity in the basin. More recently, the DRBC has stated that it will consider new regulations that would ban natural gas production activity, including hydraulic fracturing, in the basin. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing).

The requirements for permits or authorizations to conduct these activities vary depending on the location where such drilling and completion activities will be conducted. Several jurisdictions have adopted or considered adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations, or to ban hydraulic fracturing altogether. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and any conditions which may be imposed in connection with the granting of the permit. See “—Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies and third parties on favorable terms could impede operations and construction.” Certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In addition, some local jurisdictions have adopted or considered adopting land use restrictions, such as city or municipal ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular. Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG and our ability to develop commercially viable LNG facilities.

Indigenous Communities. Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which states that governments are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations, such as are required for our Brazilian operations, are consulted through appropriate procedures and through their representative institutions, particularly using the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for our operations, we are required to comply with the requirements of, consult with, and obtain certain authorizations from a number of institutions regarding the protection of indigenous interests: The Brazilian Institute of Enviornment and Renewable Resources, local environmental authorities in the localities in which we operate, the Federal Public Prosecutor’s Office and the National Indian Foundation (Fundação Nacional do Índio or “FUNAI”) (for indigenous people) or Palmares Cultural Foundation (Fundação Cultural Palmares) (for Quilombola communities).

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Additionally, the American Convention on Human Rights (“ACHR”), to which Brazil is a party, sets forth rights and freedoms prescribed for all persons, including property rights without discrimination due to race, language, and national or social origin. The ACHR also provides for consultation with indigenous communities regarding activities that may affect the integrity of their land and natural resources. If Brazil’s legal process for consultation and the protection of indigenous rights is challenged under the ACHR and found to be inadequate, it could result in orders or judgments that could ultimately adversely impact our operations. For example, in February 2020, the Interamerican Court of Human Rights (“IACtHR”) found that Argentina had not taken adequate steps, in law or action, to ensure the consulting of indigenous communities and obtaining those communities’ free prior and informed consent for a project impacting their territories. IACtHR further found that Argentina had thus violated the ACHR due to infringements on the indigenous communities’ rights to property, cultural identity, a healthy environment, and adequate food and water by failing to take effective measures to stop harmful, third-party activities on the indigenous communities’ traditional land. As a result, IACtHR ordered Argentina, among other things, to achieve the demarcation and grant of title to the indigenous communities over their territory and the removal of third parties from the indigenous territory. We cannot predict whether this decision will result in challenges regarding the adequacy of existing Brazilian legal requirements related to the protection of indigenous rights, changes to the existing Brazilian government body consultation process, or impact our existing development agreements or negotiations for outstanding development agreements with indigenous communities in the areas in which we operate.

There are several indigenous communities that surround our operations in Brazil. Certain of our subsidiaries have entered into agreements with some of these communities that mainly provide for the use of their land for our operations, provide compensation for any potential adverse impact that our operations may indirectly cause to them, and negotiations with other such communities are ongoing. If we are not able to timely obtain the necessary authorizations or obtain them on favorable terms for our operations in areas where indigenous communities reside, our relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to our operations, we could face construction delays, increased costs, or otherwise experience adverse impacts on its business and results of operations.

Offshore operations. Our operations in international waters and in the territorial waters of other countries are regulated by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which we operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, the handling and disposal of hazardous substances and wastes and the management of ballast water. The International Maritime Organization (“IMO”) International Convention for the Prevention of Pollution from Ships of 1973, as amended from time to time, and generally referred to as “MARPOL,” can affect operations of our chartered vessels. In addition, our chartered LNG vessels may become subject to the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea (the “HNS Convention”), adopted in 1996 and subsequently amended by a Protocol to the HNS Convention in April 2010. Other regulations include, but are not limited to, the designation of Emission Control Areas under MARPOL, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as amended from time to time, the International Convention on Civil Liability for Bunker Oil Pollution Damage, the IMO International Convention for the Safety of Life at Sea of 1974, as amended from time to time, the International Safety Management Code for the Safe Operations of Ships and for Pollution Prevention, the IMO International Convention on Load Lines of 1966, as amended from time to time and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004.

In particular, development of offshore operations of natural gas and LNG are subject to extensive environmental, industry, maritime and social regulations. For example, the development and operation of our new FLNG facility off the coast of Altamira, State of Tamaulipas, is subject to regulation by Mexico’s Ministry of Energy (Secretaría de Energía) (“SENER”), Mexico's National Hydrocarbon Commission (“CNH”), the National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”), among other relevant Mexican regulatory bodies. The laws and regulations governing activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidelines as the industry develops. Such regulations are subject to change, so it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. In addition, our operations in waters off the coast of Mexico are subject to regulation by ASEA. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are also relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidelines as the industry modernizes and adapts to market

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changes. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters.

Moreover, the overall trends are towards more regulations and more stringent requirements which are likely to add to our costs of doing business. For example, IMO regulations limit the sulfur content of fuel oil for ships to 0.5 weight percent starting thus increasing the cost of fuel and increasing expenses for us. Similarly, the European Union extended its emissions trading scheme to maritime transport to reduce GHG emissions from vessels. We contract with industry leading vessel providers in the LNG market and look for them to take the lead in maintaining compliance with all such requirements, although the terms of our charter agreements may call for us to bear some or all of the associated costs. While we believe we are similarly situated with respect to other companies that charter vessels, we cannot assure you that these requirements will not have a material effect on our business.

Our chartered vessels operating in U.S. waters, now or in the future, will also be subject to various federal, state and local laws and regulations relating to protection of the environment, including the OPA, the CERCLA, the CWA and the CAA. In some cases, these laws and regulations require governmental permits and authorizations before conducting certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. As with the industry generally, our chartered vessels’ operations will entail risks in these areas, and compliance with these laws and regulations, which may be subject to frequent revisions and reinterpretation, may increase our overall cost of business.

We are subject to numerous governmental export laws, and trade and economic sanctions laws and regulations, and anti-corruption laws and regulation.

We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Latin America, Europe and the other countries in which we seek to do business. We must also comply with trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. For example, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua and between 2018 and 2022, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the governments of Nicaragua and Venezuela. Following the invasion of Ukraine by Russia in 2022, U.S., European, U.K. and other governmental authorities imposed a number of sanctions against entities and individuals in Russia or connected to Russia, including sanctions specifically targeting the Russian oil and gas industry. Violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to, (i) having to suspend our development or operations on a temporary or permanent basis, (ii) being unable to recuperate prior invested time and capital or being subject to lawsuits, or (iii) investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.

We are also subject to anti-corruption laws and regulations, including the FCPA, the U.K. Bribery Act and local anti-bribery laws, which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently operate present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Brazil and Mexico. Furthermore, our strategy has been, and continues to be, dependent in part on our ability to expand our operations in additional emerging markets, including in Latin America, Asia and Africa. Efforts to expand our operations in these markets could expose us to additional risks related to anti-corruption laws and regulations. Although we have adopted policies and procedures that are designed to assist us, our officers, directors, employees and other intermediaries in complying with the FCPA and other anti-corruption laws and regulations, developing, implementing and maintaining policies and procedures is a complex endeavor, particularly given the high level of complexity of these laws and regulations. There is no assurance that these policies and procedures have or will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our officers, directors, employees and other intermediaries with respect to our business or any businesses that we may acquire, particularly in high risk jurisdictions.

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Failure to comply with trade and economic sanctions laws and anti-corruption laws and regulations, including the FCPA, the U.K. Bribery Act and local anti-bribery laws, may subject us to costly and intrusive criminal and civil investigations as well as significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and controls, the imposition of an independent compliance monitor, as well as potential personnel changes and disciplinary actions. In addition, non-compliance with such laws could constitute a breach of certain representations, warranties and covenants in our commercial or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial or debt agreements could trigger an event of default under our other agreements, including our debt agreements. Any adverse finding against us could also negatively affect our relationship and reputation with current and potential customers and regulators. In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries. On occasion, we also use third-party agents and other intermediaries to assist us in exploring and entering new markets and to retain business. Violations of applicable import, export, trade and economic sanctions, and anti-corruption laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. The occurrence of any of these events could have a material adverse impact on our business, results of operations, financial condition, reputation, liquidity and future business prospects. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may change and be amended or strengthened over time.

Any such violation of applicable sanctions, embargo and anti-corruption laws and regulations could result in fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and conduct our business. In addition, certain financial institutions may have policies against lending or extending credit to companies that have contracts with U.S. embargoed countries or countries identified by the U.S. government as state sponsors of terrorism, which could adversely affect our ability to access funding and liquidity, our financial condition and prospects.

Our charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect their business.

None of our vessels have called on ports located in countries subject to comprehensive sanctions and embargoes imposed by the U.S. government or countries identified by the U.S. government as state sponsors of terrorism. When we charter our vessels to third parties we conduct comprehensive due diligence of the charterer and include contractual prohibitions on the charterer calling on ports in countries subject to comprehensive U.S. sanctions or otherwise engaging in commerce with such countries. However, our vessels may be sub-chartered out to a sanctioned party or call on ports of a sanctioned nation on charterers’ instruction, and without our knowledge or consent. If our charterers or sub-charterers violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, those violations could in turn negatively affect our reputation and cause us to incur significant costs associated with responding to any investigation into such violations.

Increasing transportation regulations may increase our costs and negatively impact our results of operations.

We are developing a transportation system specifically dedicated to transporting LNG using ISO tank containers and trucks to our customers and facilities. This transportation system may include trucks that we or our affiliates own and operate. Any such operations would be subject to various trucking safety regulations in the various countries where we operate, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, and transportation of hazardous materials. To a large degree, intrastate motor carrier operations are subject to state and/or local safety regulations that mirror federal regulations but also regulate the weight and size dimensions of loads. Any trucking operations would be subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include changes in environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements, requirements to use electric vehicles or limits on vehicle weight and size. In addition to increased costs, fines and penalties, any non-compliance or violation of these regulations, could result in the suspension of our operations, which could have a material adverse effect on our business and consolidated results of operations and financial position.

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Our chartered vessels operating in certain jurisdictions, including the United States, now or in the future, may be subject to cabotage laws, including the Merchant Marine Act of 1920, as amended (the “Jones Act”).

Certain activities related to our logistics and shipping operations may constitute “coastwise trade” within the meaning of laws and regulations of the U.S. and other jurisdictions in which we operate. Under these laws and regulations, often referred to as cabotage laws, including the Jones Act in the U.S., only vessels meeting specific national ownership, crewing and registration requirements or which are subject to an exception or exemption, may engage in such “coastwise trade.” When we operate or charter foreign-flagged vessels, we do so within the current interpretation of such cabotage laws with respect to permitted activities for foreign-flagged vessels. Significant changes in cabotage laws or to the interpretation of such laws in the places where we operate could affect our ability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in those waters. If we do not continue to comply with such laws and regulations, we could incur severe penalties, such as fines or forfeiture of any vessels or their cargo, and any noncompliance or allegations of noncompliance could disrupt our operations in the relevant jurisdiction. Any noncompliance or alleged noncompliance could have a material adverse effect on our reputation, our business, our results of operations and cash flows, and could weaken our financial condition.

We may not own the land on which our projects are located and are subject to leases, rights-of-ways, easements and other property rights for our operations.

We have obtained long-term leases and corresponding rights-of-way agreements and easements with respect to the land on which various of our projects are located, including the Jamaica Facilities, the pipeline connecting the Montego Bay Facility to the Bogue Power Plant (as defined herein), the San Juan Facility and the CHP Plant are situated, facilities in Brazil such as the Garuva-Itapoa pipeline connecting the TBG pipeline to the Sao Francisco do Sul terminal, rights of way to the Petrobras/Transpetro OSPAR oil pipeline facilities, among others. In addition, our operations will require agreements with ports proximate to our facilities capable of handling the transload of LNG direct from our occupying vessel to our transportation assets. We may not own the land on which these facilities are located. As a result, we are subject to the possibility of increased costs to retain necessary land use rights as well as applicable law and regulations, including permits and authorizations from governmental agencies or third parties. If we were to lose these rights or be required to relocate, we would not be able to continue our operations at those sites and our business could be materially and adversely affected. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate our assets as anticipated, or at all, which could negatively affect our business, results of operations and financial condition.

We could be negatively impacted by environmental, social, and governance (“ESG”) and sustainability-related matters.

Governments, investors, customers, employees and other stakeholders are increasingly focusing on corporate ESG practices and disclosures, and expectations in this area are rapidly evolving. We have announced, and may in the future announce, sustainability-focused goals, initiatives, investments and partnerships. These initiatives, aspirations, targets or objectives reflect our current plans and aspirations and are not guarantees that we will be able to achieve them. Our efforts to accomplish and accurately report on these initiatives and goals present numerous operational, regulatory, reputational, financial, legal, and other risks, any of which could have a material negative impact, including on our reputation and stock price.

In addition, the standards for tracking and reporting on ESG matters are relatively new, have not been harmonized and continue to evolve. Our selection of disclosure frameworks that seek to align with various voluntary reporting standards may change from time to time and may result in a lack of comparative data from period to period. Moreover, our processes and controls may not always align with evolving voluntary standards for identifying, measuring, and reporting ESG metrics, our interpretation of reporting standards may differ from those of others, and such standards may change over time, any of which could result in significant revisions to our goals or reported progress in achieving such goals. In this regard, the criteria by which our ESG practices and disclosures are assessed may change due to the quickly evolving landscape, which could result in greater expectations of us and cause us to undertake costly initiatives to satisfy such new criteria. The increasing attention to corporate ESG initiatives could also result in increased investigations and litigation or threats thereof. If we are unable to satisfy such new criteria, investors may conclude that our ESG and sustainability practices are inadequate. If we fail or are perceived to have failed to achieve previously announced initiatives or goals or to accurately disclose our progress on such initiatives or goals, our reputation, business, financial condition and results of operations could be adversely impacted.

Information technology failures and cyberattacks could affect us significantly.

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We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected. We face various security threats, including cybersecurity threats from third parties and unauthorized users to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities, liquefaction facilities, and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our network systems and storage and other business applications, and the systems and storage and other business applications maintained by our third-party providers, have been in the past, and may be in the future, subjected to attempts to gain unauthorized access to our network or information, malfeasance or other system disruptions.

Our implementation of various technologies, procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities, liquefaction facilities, and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.

Our current operations and future projects are subject to the inherent risks associated with construction of energy-related infrastructure, LNG, natural gas, power and maritime operations, shipping and transportation of hazardous substances, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, acts of aggression or terrorism, and other risks or hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the facilities, liquefaction facilities and assets or damage to persons and property. We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not generally carry business interruption insurance or political risk insurance with respect to political disruption in the countries in which we operate and that may in the future experience significant political volatility. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses or delays to our development timelines, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Even if we choose to carry insurance for these events in the future, it may not be adequate to protect us from loss, which may include, for example, losses as a result of project delays or losses as a result of business interruption related to a political disruption. Any attempt to recover from loss from political disruption may be time-consuming and expensive, and the outcome may be uncertain. In addition, our insurance may be voidable by the insurers as a result of certain of our actions. Furthermore, we may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult or costly for us to obtain.

Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.

We depend to a large extent on the services of our chief executive officer, Wesley R. Edens, our other executive officers and other key employees. Mr. Edens does not have an employment agreement with us. The loss of the services of Mr. Edens or one or more of our other key executives or employees could disrupt our operations and increase our exposure to the other risks described in this Item 1A. Risk Factors. We do not maintain key man insurance on Mr. Edens or any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

We may experience increased labor costs and regulation, and the unavailability of skilled workers or our failure to attract and retain qualified personnel, as well as our ability to comply with such labor laws, could adversely affect us.

We are dependent upon the available labor pool of skilled employees for the construction and operation of our facilities and liquefaction facilities, as well as our FSRUs, FLNGs and LNG carriers. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our infrastructure and assets and to provide our customers with the highest quality service. In addition, the tightening of the labor market due to the shortage of skilled employees may affect our ability to hire and retain skilled employees, impair our operations and require us to pay increased wages. We are subject to labor laws in the

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jurisdictions in which we operate and hire our personnel, which can govern such matters as minimum wage, overtime, union relations, local content requirements and other working conditions. For example, Brazil, where some of our vessels operate, require we hire a certain portion of local personnel to crew our vessels. Any inability to attract and retain qualified local crew members could adversely affect our operations, business, results of operations and financial condition. In addition, jurisdiction-specific employment, labor, and subcontracting laws may affect contracting strategies and impact construction and operations. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations, could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

Our business could be affected adversely by labor disputes, strikes or work stoppages.

Some of our employees, particularly those in our Latin American operations, are represented by a labor union and are covered by collective bargaining agreements pursuant to applicable labor legislation. As a result, we are subject to the risk of labor disputes, strikes, work stoppages and other labor-relations matters. We could experience a disruption of our operations or higher ongoing labor costs, which could have a material adverse effect on our operating results and financial condition. Future negotiations with the unions or other certified bargaining representatives could divert management attention and disrupt operations, which may result in increased operating expenses and lower net income. Moreover, future agreements with unionized and non-unionized employees may be on terms that are not as attractive as our current agreements or comparable to agreements entered into by our competitors. Labor unions could also seek to organize some or all of our non-unionized workforce.

Risks Related to the Jurisdictions in Which We Operate

We are subject to the economic, political, social and other conditions in the jurisdictions in which we operate.

Our projects are located in the United States (including Puerto Rico), the Caribbean, Brazil, Mexico, Ireland, Nicaragua and other geographies and we have operations and derive revenues from additional markets. Furthermore, part of our strategy consists in seeking to expand our operations to other jurisdictions. As a result, our projects, operations, business, results of operations, financial condition and prospects are materially dependent upon economic, political, social and other conditions and developments in these jurisdictions. Some of these countries have experienced political, security, and social economic instability in the recent past and may experience instability in the future, including changes, sometimes frequent or marked, in energy policies or the personnel administering them, expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions or controls, currency fluctuations, royalty and tax increases and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of social unrest, terrorism, corruption and bribery. For example, in 2019, public demonstrations in Puerto Rico led to the governor’s resignation and the resulting political change interrupted the bidding process for the privatization of PREPA’s transmission and distribution systems. While our operations to date have not been materially impacted by the demonstrations or political changes in Puerto Rico, any substantial disruption in our ability to perform our obligations under any agreements with PREPA and/or Puerto Rico Public - Private Partnerships Authority (P3A) could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict how our relationship that one of our subsidiaries, as agent of PREPA, could change their role as operator of PREPA's legacy generation assets. Additionally, PREPA may seek to find alternative power sources or purchase substantially less natural gas from us than what we currently expect to sell to PREPA. In addition, we cannot predict how local sentiment and support for our subsidiaries’ operations in Puerto Rico could change now that Puerto Rico’s power generation systems have been privatized. Should our operations face material local opposition, it could materially adversely affect our ability to perform our obligations under our contracts or could materially adversely impact PREPA or any applicable governmental counterparty’s performance of its obligations to us. The governments in these jurisdictions differ widely with respect to structure, constitution and stability and some countries lack mature legal and regulatory systems. As our operations depend on governmental approval and regulatory decisions, we may be adversely affected by changes in the political structure or government representatives in each of the countries in which we operate. In addition, these jurisdictions, particularly emerging countries, are subject to risk of contagion from the economic, political and social developments in other emerging countries and markets.

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Furthermore, some of the regions in which we operate have been subject to significant levels of terrorist activity and social unrest, particularly in the shipping and maritime industries. Past political conflicts in certain of these regions have included attacks on vessels, mining of waterways and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. Tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, Africa or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries. See “—Our Charterers may inadvertently violate applicable sanctions and/or call on ports located in, or engage in transactions with, countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect their business.” We do not, nor do we intend to, maintain insurance (such as business interruption insurance or terrorism) against all of these risks and losses. Any claims covered by insurance will be subject to deductibles, which may be significant, and we may not be fully reimbursed for all the costs related to any losses created by such risks. See “—Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.” As a result, the occurrence of any economic, political, social and other instability or adverse conditions or developments in the jurisdictions in which we operate, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.

While our consolidated financial statements are presented in U.S. dollars, we generate revenues and incur operating expenses and indebtedness in local currencies in the countries where we operate, such as, among others, the euro, the Mexican peso and the Brazilian real. The amount of our revenues denominated in a particular currency in a particular country typically varies from the amount of expenses or indebtedness incurred by our operations in that country given that certain costs may be incurred in a currency different from the local currency of that country, such as the U.S. dollar. Therefore, fluctuations in exchange rates used to translate other currencies into U.S. dollars could result in potential losses and reductions in our margins resulting from currency fluctuations, which may impact our reported consolidated financial condition, results of operations and cash flows from period to period. These fluctuations in exchange rates will also impact the value of our investments and the return on our investments. Additionally, some of the jurisdictions in which we operate may limit our ability to exchange local currency for U.S. dollars and elect to intervene by implementing exchange rate regimes, including sudden devaluations, periodic mini devaluations, exchange controls, dual exchange rate markets and a floating exchange rate system. There can be no assurance that non-U.S. currencies will not be subject to volatility and depreciation or that the current exchange rate policies affecting these currencies will remain the same. For example, the Mexican peso and the Brazilian real have experienced significant fluctuations relative to the U.S. dollar in the past. We may choose not to hedge, or we may not be effective in efforts to hedge, this foreign currency risk. See “—Risks Related to our Business—Any use of hedging arrangements may adversely affect our future operating results or liquidity.” Depreciation or volatility of these currencies against the U.S. dollar could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us and may cause our expenses to increase from time to time relative to our revenues as a result of fluctuations in exchange rates, which could affect the amount of net income that we report in future periods.

Risks Related to Ownership of Our Class A Common Stock

The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders.

The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume in our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above your purchase price, if at all. The market price of our Class A common stock may fluctuate or decline significantly in the future. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our Class A common stock include:

•a shift in our investor base;

•our quarterly or annual earnings, or those of other comparable companies;

•actual or anticipated fluctuations in our operating results;

•changes in accounting standards, policies, guidance, interpretations or principles;

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•announcements by us or our competitors of significant investments, acquisitions or dispositions;

•the failure of securities analysts to cover our Class A common stock;

•changes in earnings estimates by securities analysts or our ability to meet those estimates;

•the operating and share price performance of other comparable companies;

•overall market fluctuations;

•general economic conditions; and

•developments in the markets and market sectors in which we participate.

Stock markets in the United States have experienced extreme price and volume fluctuations. Market fluctuations, as well as general political and economic conditions such as acts of terrorism, prolonged economic uncertainty, a recession or interest rate or currency rate fluctuations, could adversely affect the market price of our Class A common stock.

In the past, securities class action litigation has often been brought against companies following periods of volatility in the market price of their securities. We are currently subject to a putative securities class action complaint relating to a drop in our share price and could become involved in additional litigation of this type in the future if our share price is volatile for any reason. This type of litigation could result in reputational damage, substantial costs and a diversion of management's attention and resources needed to successfully run our business.

A small number of our original investors have the ability to direct the voting of a significant amount of our common stock, and their interests may conflict with those of our other stockholders.

As of December 31, 2024, affiliates of certain entities controlled by Wesley R. Edens, Randal A. Nardone and affiliates of Fortress Investment Group LLC (“Founder Entities”) owned an aggregate of approximately 92,530,510 shares of Class A common stock, representing approximately 33.5% of our voting power, and affiliates of Energy Transition Holdings LLC, party to the Shareholders' Agreement, own an aggregate of approximately 25,559,846 shares of our Class A common stock, representing approximately 9.2% of the voting power of our Class A common stock. The beneficial ownership of almost 50% of our voting stock means affiliates of the Founder Entities and Energy Transition Holdings LLC are able to have significant influence over matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of these parties with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders, including holders of the Class A common stock.

Given this concentrated ownership, the affiliates of the Founder Entities and Energy Transition Holdings LLC would have significant influence over any potential acquisition of us. The existence of a significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the concentration of stock ownership with affiliates of the Founder Entities and Energy Transition Holdings LLC may adversely affect the trading price of our securities, including our Class A common stock, to the extent investors perceive a disadvantage in owning securities of a company with a significant stockholder.

Furthermore, New Fortress Energy Holdings has assigned, pursuant to the terms of the Shareholders’ Agreement, to the Founder Entities, New Fortress Energy Holdings’ right to designate a certain number of individuals to be nominated for election to our board of directors so long as its assignees collectively beneficially own at least 5% of the outstanding Class A common stock. The Shareholders’ Agreement provides that the parties to the Shareholders’ Agreement (including certain former members of New Fortress Energy Holdings) shall vote their stock in favor of such nominees. In addition, our Certificate of Incorporation provides the Founder Entities the right to approve certain material transactions so long as the Founder Entities and their affiliates collectively, directly or indirectly, own at least 30% of the outstanding Class A common stock.

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Future sales and issuances of our Class A common stock, securities convertible or exchangeable into our Class A common stock or rights to purchase our Class A common stock could result in additional dilution of the percentage ownership of our shareholders and may cause our share price to fall.

To raise capital, we may sell substantial amounts of Class A common stock or securities convertible into our exchangeable for Class A common stock. These future issuances of Class A common stock or Class A common stock-related securities to purchase Class A common stock, together with the exercise of outstanding restricted stock units and any additional shares issued in connection with other transactions, if any, may result in material dilution to our investors. Such sales may also result in material dilution to our existing shareholders, and new investors could gain rights, preferences and privileges senior to those of holders of our Class A common stock. In particular, on October 1, 2024, we exchanged 96,746 shares of our Series A Convertible Preferred Stock for 96,746 shares of our Series B Convertible Preferred Stock. Such shares are convertible at the option of the holders thereof into shares of Class A common stock on the terms set forth in the certificate of designations governing the Series B Convertible Preferred Stock. Additionally, on December 6, 2024, we issued 15,700,998 shares of our Class A common stock in satisfaction of our commitment fee obligations under the Exchange and Subscription Agreement in connection with the issuance of the New 2029 Notes.

Our Certificate of Incorporation and By-Laws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their Class A common stock.

Our Certificate of Incorporation and By-Laws authorize our board of directors to issue preferred stock (including the Series B Convertible Preferred Stock) without stockholder approval in one or more series, designate the number of stock constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our Certificate of Incorporation and By-Laws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our security holders. These provisions include:

•dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;

•providing that any vacancies may, except as otherwise required by law, or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum (provided that vacancies that results from newly created directors requires a quorum);

•permitting special meetings of our stockholders to be called only by (i) the chairman of our board of directors, (ii) a majority of our board of directors, or (iii) a committee of our board of directors that has been duly designated by the board of directors and whose powers include the authority to call such meetings;

•prohibiting cumulative voting in the election of directors;

•establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of the stockholders; and

•providing that the board of directors is expressly authorized to adopt, or to alter or repeal certain provisions of our organizational documents to the extent permitted by law.

Additionally, our Certificate of Incorporation provides that we have opted out of Section 203 of the Delaware General Corporation Law. However, our Certificate of Incorporation includes a similar provision, which, subject to certain exceptions, prohibits us from engaging in a business combination with an “interested stockholder,” unless the business combination is approved in a prescribed manner. Subject to certain exceptions, an “interested stockholder” means any person who, together with that person’s affiliates and associates, owns 15% or more of our outstanding voting stock or an affiliate or associate of ours who owned 15% or more of our outstanding voting stock at any time within the previous three years, but shall not include any person who acquired such stock from the Founder Entities or Energy Transition Holdings LLC (except in the context of a public offering) or any person whose ownership of stock in excess of 15% of our outstanding voting stock is the result of any action taken solely by us. Our Certificate of Incorporation provides that the Founder Entities and Energy Transition Holdings LLC and any of their respective direct or indirect transferees, and any group as to which such persons are a party, do not constitute “interested stockholders” for purposes of this provision.

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Our By-Laws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our By-Laws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is, to the fullest extent permitted by applicable law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers or employees arising pursuant to any provision of our organizational documents or the Delaware General Corporation Law, or (iv) any action asserting a claim against us or any of our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in our stock will be deemed to have notice of, and consented to, the provisions described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it considers more likely to be favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our organizational documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, results of operations or prospects.

The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and we do not expect to pay dividends for the foreseeable future.

We do not expect to pay dividends for the foreseeable future. Any future declaration and payment of dividends to holders of our Class A common stock will be at the discretion of our board of directors in accordance with applicable law and significant restrictions imposed by our debt agreements, and after taking into account various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, restrictions imposed by our debt agreements, our taxable income, our operating expenses and other factors our board of directors deem relevant. Because we are a holding company and have no direct operations, we will only be able to pay dividends in the future from our available cash on hand and any funds we receive from our subsidiaries and our ability to receive distributions from our subsidiaries may be limited by the financing agreements to which they are subject.

The incurrence or issuance of debt which ranks senior to our Class A common stock upon our liquidation and future issuances of equity or equity-related securities, which would dilute the holdings of our existing Class A common stockholders and may be senior to our Class A common stock for the purposes of making distributions, periodically or upon liquidation, may negatively affect the market price of our Class A common stock.

We have incurred and may in the future incur or issue debt or issue equity or equity-related securities to finance our operations, acquisitions or investments. Upon our liquidation, lenders and holders of our debt and holders of our preferred stock, such as the Series A Convertible Preferred Stock that was issued upon closing of the PortoCem acquisition, would receive a distribution of our available assets before Class A common stockholders. Any future incurrence or issuance of debt would increase our interest cost and could adversely affect our results of operations and cash flows. We are not required to offer any additional equity securities to existing Class A common stockholders on a preemptive basis. Therefore, additional issuances of Class A common stock, whether directly, through convertible securities, such as the Series A Convertible Preferred Stock, or exchangeable securities (including limited partnership interests in our operating partnership), warrants or options, will dilute the holdings of our existing Class A common stockholders and such issuances, or the perception of such issuances, may reduce the market price of our Class A common stock. Any preferred stock issued by us would likely, and the Series A Convertible Preferred Stock has a preference on distribution payments, periodically or upon liquidation, which could eliminate or otherwise limit our ability to make distributions to Class A common stockholders. Because our decision to incur or issue additional debt or equity or equity-related securities (other than the Series A Convertible Preferred Stock) in the future will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. Thus, Class A common stockholders bear the risk that our future incurrence or issuance of debt or issuance of equity or equity-related securities will adversely affect the market price of our Class A common stock.

We may issue additional preferred stock, the terms of which could adversely affect the voting power or value of our Class A common stock.

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Our Certificate of Incorporation and By-Laws authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock in respect of dividends and distributions, as our board of directors may determine. As part of the PortoCem Acquisition, we issued 96,746 shares of the Series A Convertible Preferred Stock, which were subsequently exchanged for an equal number of shares of our Series B Convertible Preferred Stock. The terms of the Series B Convertible Preferred Stock or one or more classes or series of other preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock. For example, each share of the Series A Convertible Preferred Stock has a liquidation preference of $1,000.

Sales or issuances of our Class A common stock could adversely affect the market price of our Class A common stock.

Sales of substantial amounts of our Class A common stock in the public market, or the perception that such sales might occur, could adversely affect the market price of our Class A common stock. The issuance of our Class A common stock in connection with property, portfolio or business acquisitions or the exercise of outstanding options or otherwise could also have an adverse effect on the market price of our Class A common stock.

An active, liquid and orderly trading market for our Class A common stock may not be maintained and the price of our Class A common stock may fluctuate significantly.

An active, liquid and orderly trading market for our Class A common stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock.

General Risks

We are a holding company and our operational and consolidated financial results are dependent on the results of our subsidiaries, affiliates, joint ventures and special purpose entities in which we invest.

We conduct our business mainly through our operating subsidiaries and affiliates, including joint ventures and other special purpose entities, which are created specifically to participate in projects or manage a specific asset. Our ability to meet our financial obligations is therefore related in part to the cash flow and earnings of our subsidiaries and affiliates and the ability or willingness of these entities to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments, which are governed by various shareholder agreements, joint venture financing and operating arrangements. In addition, some of our operating subsidiaries, joint venture and special purpose entities are subject to restrictive covenants related to their indebtedness, including restrictions on dividend distributions. Any additional debt or other financing could include similar restrictions, which would limit their ability to make distributions or other transfers of earnings to us in the form of dividends, loans or other advances and payments. Similarly, we may fail to realize anticipated benefits of any joint venture or similar arrangement, which could adversely affect our financial condition and results of operation.

We may engage in mergers, sales and acquisitions, divestments, reorganizations or similar transactions related to our businesses or assets in the future and we may fail to successfully complete such transaction or to realize the expected value.

In furtherance of our business strategy, we may engage in mergers, purchases or sales, divestments, reorganizations or other similar transactions related to our businesses or assets in the future. Any such transactions may be subject to significant risks and contingencies, including the risk of integration, valuation and successful implementation, and we may not be able to realize the benefits of any such transactions. We may also engage in sales of our assets or sale and leaseback transactions that seek to monetize our assets and there is no guarantee that such sales of assets will be executed at the prices we desire or higher than the values we currently carry these assets at on our balance sheet. We do not know if we will be able to successfully complete any such transactions or whether we will be able to retain key personnel, suppliers or distributors. Our ability to successfully implement our strategy through such transactions depends upon our ability to identify, negotiate and complete suitable transactions and to obtain the required financing on terms acceptable to us. These

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efforts could be expensive and time consuming, disrupt our ongoing business and distract management. If we are unable to successfully complete our transactions, our business, financial condition, results of operations and prospects could be materially adversely affected.

A change in tax laws in any country in which we operate could adversely affect us.

Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing laws, treaties and regulations in and between the countries in which we operate. Our tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, regulations, or treaties, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing businesses and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions. Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect. For example, the Organization for Economic Cooperation and Development is coordinating negotiations among more than 140 countries with the goal of achieving consensus around substantial changes to international tax policies, including the implementation of a minimum global effective tax rate of 15%. Various countries have implemented the legislation and others may in the future, which could increase our effective tax rate.

We have been and may be involved in legal proceedings and may experience unfavorable outcomes.

We have been and may in the future be subject to material legal proceedings in the course of our business or otherwise, including, but not limited to, actions relating to contract disputes, business practices, intellectual property, real estate and leases, and other commercial, tax, regulatory and permitting matters. Such legal proceedings may involve claims for substantial amounts of money or for other relief or might necessitate changes to our business or operations, and the defense of such actions may be both time-consuming and expensive. Moreover, the process of litigating requires substantial time, which may distract our management. Even if we are successful, any litigation may be costly, and may approximate the cost of damages sought. These actions could also expose us to adverse publicity, which might adversely affect our reputation and therefore, our results of operations. Further, if any such proceedings were to result in an unfavorable outcome, it could have an adverse effect on our business, financial position and results of operations.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our share price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose viability in the financial markets, which in turn could cause our share price or trading volume to decline.

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We are unable to predict the extent to which global pandemics and health crises will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how a global pandemic may affect our customers and suppliers.

The COVID-19 pandemic caused economic disruptions in various regions, disruptions in global supply chains, significant volatility and disruption of financial markets and in the price of oil and other commodities. Any future global health crisis or pandemic could make, travel and commercial activity significantly more cumbersome and less efficient compared to pre-pandemic conditions. Because the severity, magnitude and duration of any such crisis or pandemic and its economic consequences are uncertain, rapidly-changing and difficult to predict, its impact on our operations and financial performance, as well as its impact on our ability to successfully execute our business strategies and initiatives, could be uncertain and difficult to predict. Further, the ultimate impact of any such pandemic or crisis on our operations and financial performance depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that may be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures); the impact of such pandemic or crisis and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs, as well as other monetary and financial policies enacted by governments (including monetary policy, taxation, exchange controls, interest rates, regulation of banking and financial services and other industries, government budgeting and public sector financing); the duration and severity of resurgences of any variants; general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery when the pandemic or crisis subsides. Our operations, financial performance and financial condition could be subjected to a number of operational financial risks in any such future pandemic or crisis. Although the services we provide are generally deemed essential, we may face negative impacts from increased operational challenges based on the need to protect employee health and safety, workplace disruptions and restrictions on the movement of people including our employees and subcontractors, and disruptions to supply chains related to raw materials and goods both at our own facilities, liquefaction facilities and at customers and suppliers. We may also experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the pandemic’s impact on the operations and financial condition of our customers and potential customers, as well as the price of available fuel options, including oil-based fuels as well as strains the pandemic places on the capacity of potential customers to evaluate purchasing our goods and services. We may experience customer requests for potential payment deferrals or other contract modifications and delays of potential or ongoing construction projects due to government guidance or customer requests. Conditions in the financial and credit markets may limit the availability of funding and pose heightened risks to future financings we may require. These and other factors we cannot anticipate could adversely affect our business, financial position and results of operations. It is possible that the longer this period of economic and global supply chain and disruption continues, the greater the uncertainty will be regarding the possible adverse impact on our business operations, financial performance and results of operations.

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

Risk Management and Strategy

The Company assesses risks from cybersecurity threats, monitors its information systems for potential vulnerabilities and tests those systems pursuant to the Company’s cybersecurity standards, processes and practices, which are integrated into the Company’s overall risk management processes. To protect the Company’s information systems from cybersecurity threats, including those related to third-party service providers, the Company uses various security tools, such as third party vendors that help the Company identify, escalate, investigate, resolve and recover from security incidents in a timely manner. The Company’s cybersecurity procedures and standards are reviewed and overseen by the Company’s cybersecurity group.

The cybersecurity group holds periodic meetings and reviews metrics it deems appropriate, including any incidents and threats, and the current state of cybersecurity issues and threats in the industry. These efforts include developing a threat model that assesses potential damage to the Company’s business and the likelihood of threat. We test the risk prioritization rankings of our threat model with external data about breaches and incidents reported by governmental agencies, including the Cybersecurity and Infrastructure Security Agency and National Security Agency. The Company

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partners with third parties to assess the effectiveness of our cybersecurity prevention and response systems and processes as needed.

For high priority incidents, the cybersecurity group will manage a risk-appropriate response, which may include the use of third-party vendors to support any investigation, response, and remediation efforts. Updates regarding any incidents are provided to management as appropriate.

To date, cybersecurity threats, including as a result of any previous cybersecurity incidents, have not materially affected and we believe are not reasonably likely to materially affect the Company, including its business strategy, results of operations or financial condition.

Governance

Management oversees the Company’s risk management process, including cybersecurity risks, and receives updates regarding any cybersecurity incidents directly from the cybersecurity group as appropriate. The cybersecurity group is led by the Chief Technology Officer, who has over 15 years of experience in information security. Management will evaluate any cybersecurity risks, concerns and issues and determine whether to escalate such issues to the Board or any of its committees. Our Board is responsible for the oversight of management as well as the business and affairs of the Company. In carrying out this responsibility, the Board discusses and receives regular updates on a wide variety of matters affecting the Company.

Risks

Please see the risk factor captioned "Information technology failures and cyberattacks could affect us significantly” in Part I, Item 1A. “Risk Factors” for additional description of cybersecurity risks and potential related impacts on the Company.

Item 3. Legal Proceedings.

We are not currently a party to any material legal proceedings. From time to time, we may become involved in various legal and regulatory claims and proceedings relating to claims arising out of our operations and activities in the normal course of business. If we become a party to proceedings in the future, we may be unable to predict with certainty the ultimate outcome of such claims and proceedings.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our Class A common stock is traded on the Nasdaq Global Select Market under the symbol “NFE.” On February 28, 2025, there were 204 holders of record of our Class A common stock. This number does not include shareholders whose shares are held for them in “street name” meaning that such shares are held for their accounts by a broker or other nominee. The actual number of beneficial shareholders is greater than the number of holders of record.

Dividends

We declared dividends of $0.10 per share of our Class A common stock totaling $61,517 during the year ended December 31, 2024, of which $41,010 have been paid. Under certain intercompany agreements entered into in conjunction with the debt exchange and refinancing transactions completed in the fourth quarter of 2024, New Fortress Energy Inc. is no longer permitted to pay dividends to common shareholders declared after September 30, 2024.

Share Performance Graph

The following graph compares the cumulative total return to shareholders on our Class A common stock relative to the S&P 500, iShares Global Clean Energy ETF Index (“ICLN”), Vanguard Energy ETF (“VDE”), and Energy Select Sector SPDR Fund ("XLE"), including reinvestment of dividends. The addition of XLE reflects that as a global energy infrastructure company, our common stock can trade in correlation with global oil, gas and consumable fuel companies, and such companies are the components of XLE.

The graph assumes that on December 31, 2019, $100 was invested in our Class A shares and in each index based on the closing market price, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.

The following Performance Graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such filing.

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Cumulative Total Return Percentage
Company / Index	December 31, 2019(1)	December 31, 2020(1)	December 31, 2021(1)	December 31, 2022(1)	December 31, 2023(1)	December 31, 2024(1)
NFE	100.0%	244.0%	56.8%	178.2%	171.4%	9.6%
S&P 500	100.0%	18.4%	52.3%	24.7%	57.5%	96.8%
iShares Global Clean Energy ETF Index ("ICLN")	100.0%	141.8%	83.3%	73.4%	38.1%	2.6%
Energy Select Sector SPDR Fund ("XLE")	100.0%	(32.5)%	3.5%	69.9%	68.8%	78.1%
Vanguard Energy ETF ("VDE")	100.0%	(33.1)%	4.6%	70.3%	70.3%	81.8%

(1)Last trading day of the month

Item 6. [Reserved.]

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors.

You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The comparison of the years ended December 31, 2023 and 2022 can be found in our Annual Report on Form 10-K for the year ended December 31, 2023 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions.

Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries.

Overview

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 this 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. Our first floating liquefaction unit, which we refer to as "Fast LNG" or "FLNG", began producing LNG in July 2024, and, once fully commissioned, we plan to source a portion of our LNG needs from this facility. 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 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 included in our Terminals and Infrastructure segment.

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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 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 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 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

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improving reliability of power generation in Puerto Rico. We receive an annual management fee and are eligible for performance-based incentive fees. The service period under the contract commenced on July 1, 2023.

La Paz Facility

In the fourth quarter of 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility also supplies our gas-fired power units located adjacent to the La Paz Facility (the “La Paz Power Plant”) and could have a maximum capacity of up to 135MW of power. We placed the La Paz Power Plant into service in the third quarter of 2023.

In the fourth quarter of 2022, we finalized short-form agreements with CFE to expand and extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and to sell the La Paz Power Plant to CFE. In the third quarter of 2024, we executed a 10-year gas sales agreement to supply natural gas to additional CFE facilities on take-or-pay basis.

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 Sao Paulo, within the city limits of Lins. We expect to participate in upcoming power auctions in Brazil scheduled for June 2025, and to the extent that we are successful in these auctions, we expect to develop a gas-fired power plant using natural gas from the Santa Catarina Facility.

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 closed in the fourth quarter of 2024.

Our LNG Supply and Cargo Sales

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Our Current Operations – Ships

Our shipping assets include Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"). Our shipping assets are included in both of our operating segments. Certain vessels are currently chartered to third parties under long-term arrangements and are included in the Energos Formation Transaction (defined below); such vessels are included in our Ships segment. At the expiration of third party charters of these vessels, we plan to utilize these vessels for our own operational purposes. Vessels we operate at our terminal operations or that we decide to sub-charter are included in our Terminals and Infrastructure segment.

In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of eleven vessels to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our Consolidated Balance Sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. In February 2024, we sold substantially all of our stake in Energos.

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 (“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 first “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.

We describe our operational and planned FLNG projects below.

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Altamira

Our first Fast LNG unit has been deployed off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million ton per annum (“MTPA”) FLNG unit utilizes CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in the process of finalizing commissioning the project. While we experienced delays in commissioning our first FLNG unit, which impacted our results of operations in 2024 and may impact our results in future periods, in July 2024, we began to produce LNG. We have placed this asset into service from an accounting perspective in the fourth quarter of 2024, and we expect to achieve run-rate production in 2025.

We expect to deploy up to two 1.4MTPA additional FLNG units onshore at the existing Altamira LNG import facility. The terminal would source also 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

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. 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.

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 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 in 2025.

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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.

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 November, ABP sought leave to appeal the High Court's decision, the High Court has not yet heard the request to leave appeal. If the leave is not granted, ABP will be directed to reconsider our permit application on accordance with Irish Law. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations.

ZeroParks

In 2020, we formed our Zero division to develop and operate facilities that produce clean hydrogen in an environmentally sustainable manner, and to invest in emerging technologies that enable the production of clean hydrogen to be more efficient and scalable. Our business plan is to build a portfolio of clean hydrogen production sites, each referred to as a ZeroPark, in key regions throughout the United States, utilizing the most efficient and reliable electrolyzer technologies.

Our first clean hydrogen project, known as ZeroPark I, is located in Beaumont, Texas. The ZeroPark I facility is sited within a 10-mile radius of the two largest refineries in the western hemisphere and numerous petrochemical manufacturers, many of which require significant amounts of hydrogen for their businesses. ZeroPark I, as planned, could use up to 200 MW of power, constructed in two distinct phases, each using 100 MW of electrolysis technology. In total, ZeroPark I is expected to produce up to 86,000 kg of clean hydrogen per day, or approximately 31,000 TPA. We have commenced design, engineering and permitting for ZeroPark I. Additionally, we have secured a binding offtake commitment for the clean hydrogen produced at ZeroPark I. Once completed, we expect ZeroPark I to be the largest green hydrogen plant in the United States.

Klondike

We recently launched Klondike, a power and data center development business dedicated to working with hyperscale customers to build and operate data centers. This venture comes in response to a significant need for turnkey digital infrastructure to support the next stage of explosive growth in artificial intelligence.

Recent Developments

In February 2025, one of our consolidated subsidiaries entered into an agreement to issue up to $350.0 million aggregate principal amount of 15% Senior Secured Notes due 2029 (the “Brazil Financing Notes”) at a purchase price of 97.75% of par. The Brazil Financing Notes bear interest at a rate of 15.0% and mature on August 30, 2029; the principal is due in full on the maturity date. Interest is payable quarterly in arrears beginning on March 30, 2025, and for the first 30 months that

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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 was used to repay the Barcarena Debentures in full.

In March 2025, we entered into an amendment to the Term Loan B Agreement. Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425.0 million. The incremental term loans are subject to the same terms as the initial Term Loan B, including interest rates and maturity date. Net proceeds will be used primarily to fund capital expenditures of our onshore Fast LNG project at Altamira, and for other corporate expenses. In connection with the amendment, all unused term loan commitments under the Term Loan A Credit Agreement were terminated.

On March 6, 2025, we entered into a Backstop Agreement (the "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 debt securities up to an aggregate principal amount sufficient to generate gross proceeds of $100.0 million with a term of at least three years from the closing date. Proceeds received would be used to satisfy the repayment of the outstanding borrowings under the Revolving Facility (defined below) required by the reduction of commitments by September 30, 2025. The Backstop Agreement would be terminated in the event that we complete the sale of assets or receives proceeds associated with a contract termination fee sufficient to satisfy such required repayment.

Other Matters

On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending.

On 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.

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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 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 from an accounting perspective in the fourth quarter of 2024. This project represents our largest ever capital project and placing the asset into service from an accounting perspective 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 this development.

While the asset is in service from an accounting perspective, we will continue to commission the asset to achieve run rate production. Such costs that enhance the asset will be capitalized on our Consolidated Balance Sheets.

•Our historical financial results do not reflect our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 93% of our LNG volumes from third parties for the year ended December 31, 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 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 sold the first full cargo from this facility on September 30, 2024, and we anticipate reaching run rate production in 2025..

•Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2024 include our Montego Bay Facility, Old Harbour Facility, 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. We are also continuing to develop our Barcarena Power Plant, PortoCem Power Plant, Puerto Sandino Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects.

Additionally, we began to deliver power to the Puerto Rican grid as part of the grid stabilization project in the second quarter of 2023. In the first quarter of 2024, our contract was terminated and assets related to the grid stabilization project were sold to PREPA. Under our new island-wide gas sale agreement with PREPA, we continue to supply gas to these power generation assets.

•Our historical financial results include the results from our investments in the common units of Hilli LLC and Energos. On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of our investment in the common units of Hilli LLC (“Hilli Common Units”), disponent owner and operator of the Hilli Episeyo (the “Hilli”) through its subsidiary Golar Hilli Corporation, in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"). As a result of this transaction, we no longer have any ownership interest in the Hilli, and their results are no longer included in NFE's results of operations.

In February 2024, the Company completed the sale of substantially all of its stake in Energos for a total consideration of $136.4 million and retaining an investment in Energos valued at $1.0 million. As a result of this transaction, we no longer include the results of Energos in our results of operations.

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Results of Operations – Three Months Ended December 31, 2024 compared to Three Months Ended September 30, 2024 and Year Ended December 31, 2024 compared to Year Ended December 31, 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.

The tables below present our segment information for the three months ended December 31, 2024 and September 30, 2024, and for the year ended December 31, 2024 and December 31, 2023:


	Three Months Ended December 31, 2024
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(3)		Consolidated
Total revenues	$	528,908	$	42,363	$	571,271	$	107,727	$	678,998
Cost of sales(1)(2)	288,398		—		288,398		—		288,398
Vessel operating expenses(5)	—		8,219		8,219		—		8,219
Operations and maintenance(5)	34,411		—		34,411		—		34,411

Segment Operating Margin	$	206,099	$	34,144	$	240,243	$	107,727	$	347,970


Three Months Ended December 31, 2024
(in thousands of $)	Consolidated





Gross margin (GAAP)	$	309,224
Depreciation and amortization	38,746
Consolidated Segment Operating Margin (Non-GAAP)	$	347,970


	Three Months Ended September 30, 2024
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(3)		Consolidated
Total revenues	$	482,200	$	43,062	$	525,262	$	42,273	$	567,535
Cost of sales(1)(2)	325,292		—		325,292		—		325,292
Vessel operating expenses(5)	—		8,254		8,254		—		8,254
Operations and maintenance(5)	32,062		—		32,062		—		32,062
Deferred earnings from contracted sales(4)	60,000		—		60,000		(60,000)		$	—
Segment Operating Margin	$	184,846	$	34,808	$	219,654	$	(17,727)	$	201,927

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Three Months Ended September 30, 2024
(in thousands of $)	Consolidated





Gross margin (GAAP)	$	166,563
Depreciation and amortization	35,364
Consolidated Segment Operating Margin (Non-GAAP)	$	201,927


	Year Ended December 31, 2024
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(3)		Consolidated
Total revenues	$	2,044,273	$	170,587	$	2,214,860	$	150,000	$	2,364,860
Cost of sales(1)(2)	1,064,667		—		1,064,667		—		1,064,667
Vessel operating expenses(5)	—		33,372		33,372		—		33,372
Operations and maintenance(5)	174,313		—		174,313		—		174,313
Deferred earnings from contracted sales(4)	150,000		—		150,000		(150,000)		—
Segment Operating Margin	$	955,293	$	137,215	$	1,092,508	$	—	$	1,092,508


Year Ended December 31, 2024
(in thousands of $)	Consolidated





Gross margin (GAAP)	$	930,494
Depreciation and amortization	162,014
Consolidated Segment Operating Margin (Non-GAAP)	$	1,092,508


	Year Ended December 31, 2023
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(3)		Consolidated
Total revenues	$	2,141,085	$	293,605	$	2,434,690	$	(21,394)	$	2,413,296
Cost of sales(1)(2)	764,828		—		764,828		112,623		877,451
Vessel operating expenses(5)	—		51,387		51,387		(5,948)		45,439
Operations and maintenance(5)	166,785		—		166,785		—		166,785
Segment Operating Margin	$	1,209,472	$	242,218	$	1,451,690	$	(128,069)	$	1,323,621


Year Ended December 31, 2023
(in thousands of $)	Consolidated





Gross margin (GAAP)	$	1,136,297
Depreciation and amortization	187,324
Consolidated Segment Operating Margin (Non-GAAP)	$	1,323,621

(1)Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are an economic hedge of commodity purchases and sales, and a realized gain of $139.1 million for the year ended December 31, 2023 was recognized as a reduction to Cost of sales in the segment measure. We recognized unrealized losses of $106.4 million on the mark-to-market value of derivative transactions for the year ended December 31, 2023, and these losses reconcile Cost of sales in the segment measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. No realized gains or losses were recognized for the year ended December 31, 2024.

We have excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6.2 million for the year ended December 31, 2023 reconcile Cost of sales in the segment

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measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. We did not incur such costs in the year ended December 31, 2024.

(2)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(3)For the year ended December 31, 2024, Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $150.0 million which were recognized during the third and fourth quarters of 2024.

In 2023, the effective share of revenues, expenses and operating margin attributable to our ownership of the common units of Hilli LLC were included in the segment measure prior to the disposition of this investment. Unrealized mark-to-market gains or losses on derivative instruments and the exclusion of non-capitalizable contract acquisition costs were also removed.

(4)Deferred earnings from contracted sales represent forward sales transactions that were contracted in the second and third quarters of 2024 and prepayment for these sales was received. Revenue has been recognized in the Consolidated Statements of Operations and Comprehensive (Loss) Income during the third and fourth quarters of 2024.

(5)Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin as defined under GAAP.

Terminals and Infrastructure Segment


	Three Months Ended,
(in thousands of $)	December 31, 2024		September 30, 2024		Change
Total revenues	$	528,908	$	482,200	$	46,708
Cost of sales (exclusive of depreciation and amortization)	288,398		325,292		(36,894)
Operations and maintenance	34,411		32,062		2,349
Deferred earnings from contracted sales	—		60,000		(60,000)
Segment Operating Margin	$	206,099	$	184,846	$	21,253


	Year Ended,
(in thousands of $)	December 31, 2024		December 31, 2023		Change
Total revenues	$	2,044,273	$	2,141,085	$	(96,812)
Cost of sales (exclusive of depreciation and amortization)	1,064,667		764,828		299,839
Operations and maintenance	174,313		166,785		7,528
Deferred earnings from contracted sales	150,000		—		150,000
Segment Operating Margin	$	955,293	$	1,209,472	$	(254,179)

Total revenue

Total revenue for the Terminals and Infrastructure Segment increased by $46.7 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024. The increase was primarily driven by income from the novation of an LNG supply contract during the fourth quarter of 2024 and higher Henry Hub index pricing, offset by lower volumes delivered and cargo sales.

•The Company novated an LNG supply contract to a customer, recognizing $235.6 million within segment revenue in the fourth quarter. NFE recognized $60.0 million of deferred earnings from contracted sales with this customer

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in the third quarter of 2024, and this prepayment is included in the reconciliation between segment revenue and consolidated revenue recognized.

•The average Henry Hub index pricing used to invoice our downstream customers increased by 29% for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024.

•Volumes delivered to downstream terminal customers decreased from 20.7 TBtu in the third quarter of 2024 to 18.4 TBtu in the fourth quarter of 2024. The decrease was due to vessel maintenance in our LNG supply chain that briefly deferred deliveries to our customers.

•Revenue recognized from cargo sales decreased during the three months ended December 31, 2024 to $91.9 million from $174.5 million during three months ended September 30, 2024.

•In the second and third quarters of 2024, we recognized an estimate of the incentive fees that we expected to earn under our contract with Genera. In the first quarter of 2025, we modified our agreement with Genera to remove all future incentive payments in exchange for a payment of $110.0 million. The subsequent modification of the agreement required us to evaluate the incentive fees recognized in 2024, and we recognized a reversal of $57.0 million of revenue that was recognized earlier in 2024.

Total revenue for the Terminals and Infrastructure Segment decreased by $96.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, and segment revenue was impacted by the following in 2024:

•For the year ended December 31, 2024, volumes delivered to downstream customers were 81.3 TBtu as compared to 68.3 TBtu for the year ended December 31, 2023. We placed the La Paz Power Plant into service during the third quarter of 2023, and recorded a full year of revenue during 2024 compared to two quarters of revenue during 2023.

•During 2024, we recognized $235.6 million of income within segment revenue from the novation of an LNG supply contract.

•Starting in the third quarter of 2023, 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. The Company provided full year of operations and maintenance services during 2024 compared to six months of services in 2023.

Although we recognized the contract novation income and 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 17% for the year ended December 31, 2024 as compared to the year ended December 31, 2023.

•The Company had $291.0 million in cargo sales for the year ended December 31, 2024. Revenue from cargo sales was $618.5 million for the year ended December 31, 2023, which included $332.0 million of contract settlements.

•In 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets in the second and third quarters of 2023. Our customer terminated the grid stabilization project in the first quarter of 2024, resulting in lower revenue from the project in 2024. However, we continue to sell volumes into these power plants under a new island-wide gas sale agreement signed with PREPA.

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 sale of our Miami Facility, we continue sourcing LNG from third parties and we expect 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

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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 $36.9 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024.

•We delivered 11% lower volumes to our customers in the fourth quarter. Our cost of LNG to supply our downstream customers increased by $8.6 million during the three months ended December 31, 2024, due to higher cost of gas purchased at $8.75 per MMBtu for the three months ended December 31, 2024 compared to $6.65 per MMBtu for the three months ended September 30, 2024.

•The higher cost of LNG to deliver to downstream customers was partially offset by lower cost of selling cargos. We incurred $35.6 million less cost of selling cargos during the fourth quarter of 2024 compared to the third quarter of 2024.

Cost of sales increased by $299.8 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023, which was attributable to the following activity:

•We incurred increased cost of LNG to supply our downstream customers of $64.5 million during the year ended December 31, 2024 due to increased volumes delivered. We delivered 19% more volume to our downstream terminal customers in the current period. Our pricing to purchase LNG for delivery to such customers was slightly lower at $7.20 per MMBtu for the year ended December 31, 2024 compared to $7.23 per MMBtu for the year ended December 31, 2023.

•Vessel costs increased by $67.0 million, for the year ended December 31, 2024 as compared to the year ended December 31, 2023. The increase is primarily driven by additional vessels being used for servicing our terminals during 2024.

•We recognized payroll and other operating costs of $101.4 million to provide services under Genera's operations and maintenance contract for the year ended December 31, 2024 compared to $35.6 million for the year ended December 31, 2023; these costs are passed onto PREPA. Only six months of such costs were incurred during the year ended December 31, 2023 as our contract commenced on July 1, 2023.

•We incurred decreased cost of LNG for cargo sales during the year ended December 31, 2024 by $19.2 million as our LNG cargo sale activity has been marginally lower in 2024.

•In the year ended December 31, 2023, realized gains of $139.1 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 2024.

The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 2024 and December 31, 2023 was $6.90 per MMBtu and $7.33 per MMBtu, respectively.

Operations and maintenance

Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales.

Operations and maintenance increased by $2.3 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024. We incurred additional operations and maintenance costs for planned maintenance at our terminals and power plants during the three months ended December 31, 2024.

Operations and maintenance increased by $7.5 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. We incurred full year of operations and maintenance costs at our La Paz Power Plant in 2024, as it was placed into service in September 2023. Additional operations and maintenance cost were also incurred at our La Paz Facility in 2024 to meet higher customer demand. The increase in costs were partially offset by lower lease costs

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incurred in 2024. The Company's contract to provide emergency power services to support the grid stabilization project was terminated in the first quarter of 2024 resulting in decreased lease expense compared to 2023.

Deferred earnings from contracted sales

In the second and third quarters of 2024, we completed forward sales receiving prepayments from the buyers of $90.0 million and $60.0 million respectively. The prepayments were based on the fair market value of these sales as compared to our supply cost, and our CODM includes these results in his evaluation of Terminals and Infrastructure operations. Revenue for these sales have been recognized in our Consolidated Statements of Operations and Comprehensive (Loss) Income in the third and fourth quarters of 2024, and as such, these deferred earnings do not impact the total segment operating margin recognized for the year ended December 31, 2024.

Ships Segment


	Three Months Ended,
(in thousands of $)	December 31, 2024		September 30, 2024		Change
Total revenues	$	42,363	$	43,062	$	(699)

Vessel operating expenses	8,219		8,254		(35)

Segment Operating Margin	$	34,144	$	34,808	$	(664)


	Year Ended,
(in thousands of $)	December 31, 2024		December 31, 2023		Change
Total revenues	$	170,587	$	293,605	$	(123,018)

Vessel operating expenses	33,372		51,387		(18,015)

Segment Operating Margin	$	137,215	$	242,218	$	(105,003)

Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for positioning and repositioning vessels as well as the reimbursement of certain vessel operating costs. As of December 31, 2024, three vessels included in the Energos Formation Transaction were leased to customers under long-term arrangements and are included in this segment.

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 (gain) on sale of assets, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

Total revenue

Total revenue for the Ships segment remained consistent from the three months ended September 30, 2024 to the three months ended December 31, 2024 with a small decrease of $0.7 million.

Total revenue for the Ships segment decreased by $123.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 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, and one vessel in 2024, lowering vessel revenue for the year ended December 31, 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

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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 between the three months ended September 30, 2024 and the three months ended December 31, 2024.

Vessel operating expenses decreased by $18.0 million for the year ended December 31, 2024 as compared to the year ended December 31, 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. We started using four vessels in 2023 and one vessel in 2024 that were in the Ships segment, in our terminal operations, resulting in lower vessel operating costs.

Other operating results


	Three Months Ended,						Year Ended,
(in thousands of $)	December 31, 2024		September 30, 2024		Change		December 31, 2024		December 31, 2023		Change
Selling, general and administrative	$	61,800	$	82,388	$	(20,588)	$	285,520	$	205,104	$	80,416
Transaction and integration costs	5,994		3,154		2,840		12,279		6,946		5,333
Depreciation and amortization	38,746		35,364		3,382		162,014		187,324		(25,310)
Asset impairment expense	10,738		1,484		9,254		16,494		10,958		5,536
Loss (gain) on sale of assets, net	422		—		422		77,562		(29,378)		106,940
Total operating expenses	117,700		122,390		(4,690)		553,869		380,954		172,915
Operating income	230,270		79,537		150,733		538,639		942,667		(404,028)
Interest expense	99,527		71,107		28,420		328,377		277,842		50,535
Other expense (income), net	52,447		(5,836)		58,283		113,077		10,408		102,669
Loss on extinguishment of debt, net	260,309		—		260,309		270,063		—		270,063
(Loss) income before income from equity method investments and income taxes	(182,013)		14,266		(196,279)		(172,878)		654,417		(827,295)
Income (loss) from equity method investments	—		—		—		—		9,972		(9,972)
Tax provision (benefit)	41,497		2,953		38,544		69,509		115,513		(46,004)
Net (loss) income	$	(223,510)	$	11,313	$	(234,823)	$	(242,387)	$	548,876	$	(791,263)

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 for the three months ended December 31, 2024 decreased by $20.6 million as compared to the three months ended September 30, 2024. The decrease was primarily driven by significant forfeitures of RSUs due to employee terminations, as well as, reduction in non-capitalizable development costs and payroll costs.

Selling, general and administrative increased by $80.4 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase was primarily due to higher share-based compensation expense and screening costs. During 2024, we granted RSUs to select officers, employees and certain non-employees, and an equity award to

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certain employees that will settle in shares of a subsidiary owning the Company's Brazilian operations. The Company recognized $50.4 million of share-based compensation expense for RSUs and other equity awards during the year ended December 31, 2024; no significant cost was recognized in the year ended December 31, 2023. In addition, the bad debt expense increased by $15.9 million for additional allowance and write-off of receivables during 2024. We also incurred higher screening costs for our development projects during 2024, offset by lower travel, payroll costs and professional fees.

Transaction and integration costs

The transaction and integration costs of $6.0 million and $12.3 million during the three months and year ended December 31, 2024, respectively, primarily relate to legal fees and other third party costs incurred by the Company in connection with the amendments of credit agreements.

Depreciation and amortization

Depreciation and amortization increased by $3.4 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024. The increase during the fourth quarter of 2024 was mostly attributable to additional depreciation of capitalized vessel-related costs.

Depreciation and amortization decreased by $25.3 million for the year ended December 31, 2024 as compared to the year ended December 31, 2023. During 2024, the Company sold turbines and related equipment to PREPA, resulting in a lower depreciation and amortization expense compared to the year ended December 31, 2023. Amortization of favorable vessel charter contracts also decreased in 2024 due to the expiration of charter contracts. The decrease in depreciation and amortization expense was partly offset by additional depreciation and amortization expense relating to PortoCem Acquisition and the La Paz Power Plant that was put into service during third quarter of 2023.

Asset impairment expense

For the year ended December 31, 2024 the Company recognized an impairment loss of $16.0 million related to the sale of our Miami facility, which includes an allocation of goodwill of $10.4 million. During year ended December 31, 2023, we recognized an impairment expense of $10.9 million for the vessel Mazo.

Loss (gain) on sale of assets, net

The Company had no significant asset sales during the third and fourth quarters of 2024. In 2023, we sold the vessel Golar Spirit and 100% of shares of Pecém and Muricy resulting in a total gain of $29.3 million. During 2024, the Company recognized a loss of $77.6 million from the sale of turbines and related equipment to the PREPA.

Interest expense

Interest expense increased by $28.4 million for the three months ended December 31, 2024 as compared to the three months ended September 30, 2024, primarily due to additional deferred financing costs and higher interest rate under new and refinanced borrowings.

Interest expense increased by $50.5 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023. The increase was primarily due to an increase in total principal outstanding for additional borrowings and amortization of related debt issuance costs, net of capitalized interest cost. The total principal balance on outstanding facilities was $9.0 billion as of December 31, 2024 as compared to total outstanding debt of $6.9 billion as of December 31, 2023.

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Other expense (income), net

Other expense, net and other income, net was $52.4 million and $5.8 million for the three months ended December 31, 2024 and September 30, 2024, respectively. Other expense, net was $113.1 million and $10.4 million for the year ended December 31, 2024 and December 31, 2023, respectively.

Other expense, net recognized in the three months ended December 31, 2024 was primarily comprised of foreign currency loss due to remeasurement of USD denominated debt in our Brazil subsidiary. The losses were partly offset by interest income, and realized and unrealized gains on foreign currency derivative contracts.

Other expense, net recognized in the year ended December 31, 2024 was primarily comprised of remeasurement losses from USD denominated foreign currency debt in Brazil, resulting from depreciation of the BRL currency. The losses were partially offset by interest income and realized and unrealized gains on foreign currency derivative contracts.

Loss on extinguishment of debt

During the fourth quarter of 2024, we repaid all of the 2025 Notes and a portion of the 2026 Notes and 2029 Notes, and recognized as a loss on extinguishment of debt totaling $235.4 million. In Brazil, we repaid the PortoCem Bridge Loan with proceeds from the PortoCem Debenture issuance and recorded a loss on extinguishment of $25.0 million.

In addition, during the first quarter of 2024, we recognized prepayment premium and unamortized financing costs of $7.9 million in connection with the prepayment of the Equipment Notes. During the same period, we also recognized a premium over the repurchase price of $1.9 million in connection with the cash tender offer to repurchase $375.0 million of the outstanding 2025 Notes. We did not have any extinguishment transactions in 2023.

Income (loss) from equity method investments

During 2023, we recognized income of $10.0 million from our equity method investment in Energos. 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 year ended December 31, 2024.

Tax provision

We recognized a tax provision of $69.5 million for the year ended December 31, 2024 compared to a tax provision of $115.5 million year ended December 31, 2023. For the year ended December 31, 2024, the tax provision was primarily driven by U.S. tax on earnings of our Puerto Rican operations and increases in valuation allowances against losses generated by our foreign operations in Brazil and Mexico.

Liquidity and Capital Resources

In the fourth quarter of 2024, we entered into a series of debt and equity transactions to extend the maturities of our corporate debt and to provide additional liquidity. In October, we issued 46,349,942 shares of our Class A common stock, at a purchase price to the public of $8.63 per share, less underwriting discounts and commissions, in a registered public offering, receiving net proceeds of approximately $387 million after underwriters' discounts, commissions and offering expenses. We also completed the Refinancing Transactions under which we issued approximately $2.7 billion of New 2029 Notes, repaid in full our 2025 Notes and repaid a portion of the 2026 Notes and 2029 Notes (each defined below), along with receiving approximately $300 million in proceeds. We also amended the terms of our Revolving Facility to extend the maturity of the majority of the commitments. Collectively these transactions extended the maturity of our corporate debt while providing additional liquidity to fund our development projects, including the completion of our first FLNG project.

We have made significant progress in extending the maturities of our long-term debt, and we continue to explore asset sales, settlement of claims and other strategic transactions (the "Transactions") that seek to optimize the value of our portfolio while providing additional liquidity and cash flow. As part of preparing the financial statements included in this Annual Report, we are required to consider the guidance in ASC 205-40, which requires us to only consider the mitigating effects of our plans only if those plans are fully implemented at the assessment date when assessing whether substantial doubt is raised about our ability to continue as a going concern. Under this guidance, we were required to exclude the effects of the Transactions from our forecast, and as such, we concluded that our current liquidity and forecasted cash flows from operations are not sufficient to support, in full, obligations as they become due. We have approved a plan to alleviate

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liquidity risk and concluded that we will have sufficient liquidity to meet its obligations as they become due over the next twelve months from the date that the consolidated financial statements were issued.

Additionally, we expect our current working capital position to improve based on the following: (1) funding received from our Brazil Financing Notes and our upsized Term Loan B; (2) expected cash flows generated from new gas sale agreements and volume growth in Puerto Rico, Mexico and Brazil; (3) sales of our own LNG generated by our first deployed Fast LNG unit; (4) continued proceeds from our asset sale program; and (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. In addition, we have begun to identify strategic partners for one or more of our primary businesses and expect to explore potential strategic partner financing, commercial ventures or assets sales to enhance our liquidity and financial flexibility.

We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions. The terms and conditions of our indebtedness include restrictive covenants that limit our ability to operate our business, incur or refinance our debt, engage in certain transactions, and require us to maintain certain financial ratios, among others, any of which may limit our ability to finance future operations and capital needs, react to changes in our business and in the economy generally, and to pursue business opportunities and activities. Following the completion of the Refinancing Transactions, our ability to undertake these activities, including our ability to incur or refinance our debt, is further limited. Furthermore, the restrictions contemplated 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.

Our remaining committed capital expenditures, inclusive of invoiced amounts in Accounts payable, is approximately $1,159 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 $433 million of our upcoming committed capital expenditures. In February 2025, we issued the Brazil Financing Notes raising $350.0 million, and in March 2025, we upsized the Term Loan B by an additional $425.0 million. Proceeds received from these financings can be used for general corporate purposes, including towards our development projects.

We expect fully completed Fast LNG units to cost between $1.0 billion and $2.0 billion per unit on average. Unlike engineering, procurement and construction agreements for traditional liquefaction construction, our contracts with vendors to construct the Fast LNG units allow us to closely control the timing of our spending and construction schedules so that we can complete each project in time frames to meet our business needs. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments.

As of December 31, 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.

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Contractual Obligations

We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2024:


(in thousands)	Total		Year 1		Years 2 to 3		Years 4 to 5		More than 5 years
Long-term debt obligations	$	14,109,482	$	1,256,887	$	3,626,265	$	5,682,953	$	3,543,377
Purchase obligations	16,973,053		1,476,592		1,512,318		1,225,575		12,758,568
Lease obligations	838,524		179,485		223,566		194,263		241,210
Total	$	31,921,059	$	2,912,964	$	5,362,149	$	7,102,791	$	16,543,155

Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2024. The principal on the PortoCem BNDES Debentures (defined below) is subject to adjustment based on inflation; the table above only includes the principal balance due as of December 31, 2024, and does not project future amounts that may be due based on inflation.

A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above.

The New Notes issued pursuant to the New 2029 Notes bear interest at the increased rate of 12.00% per annum compared with the 2025 Notes, the 2026 Notes and the 2029 Notes being refinanced, and results in an increase in long-term debt obligations. The increased debt and interest expense has been included in the table above.

Purchase obligations

We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of December 31, 2024.

We have construction purchase commitments in connection with our development projects, including our Fast LNG projects, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility, Barcarena Power Plant and PortoCem Power Plant. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued.

Lease obligations

Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, and a land lease.

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Cash Flows

The following table summarizes the changes to our cash flows for the year ended December 31, 2024 and 2023, respectively:


	Year Ended December 31,
(in thousands)	2024		2023		Change
Cash flows from:
Operating activities	$	586,742	$	824,756	$	(238,014)
Investing activities	(2,074,647)		(2,904,143)		829,496
Financing activities	2,224,568		1,528,950		695,618
Net increase (decrease) in cash, cash equivalents, and restricted cash	$	736,663	$	(550,437)	$	1,287,100

Cash provided by operating activities

Our cash flow provided by operating activities was $586.7 million for the year ended December 31, 2024, which decreased by $238.0 million from cash provided by operating activities of $824.8 million for the year ended December 31, 2023. Our results for the year ended December 31, 2024, when adjusted for non-cash items including loss on extinguishment of debt, decreased by $199.3 million from the year ended December 31, 2023. We also settled a commodity swap during the first quarter of 2023, resulting in a significant cash inflow that did not recur during 2024.

Cash used in investing activities

Our cash flow used in investing activities was $2,074.6 million for the year ended December 31, 2024, which decreased by $829.5 million from cash used in investing activities of $2,904.1 million for the year ended December 31, 2023. Cash outflows from investing activities during the year ended December 31, 2024 were used primarily for continued development of our Fast LNG project and the construction of the PortoCem Power Plant and Barcarena Power Plant. Cash outflows were offset by proceeds from the sale of assets including the sale of turbines and related equipment to PREPA, our investment in Energos, the Mazo and the Miami Facility.

Cash outflows for investing activities during the year ended December 31, 2023 were used 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, proceeds received from the sale of Pecém and Muricy, as well as proceeds received from the sale of the Spirit and a portion of our investment in equity securities.

Cash provided by financing activities

Our cash flow provided by financing activities was $2,224.6 million for the year ended December 31, 2024, which increased by $695.6 million from cash provided by financing activities of $1,529.0 million for the year ended December 31, 2023. During the year ended December 31, 2024 we had total borrowings of $5,865 million, with such borrowings primarily used to fund continued development of the Fast LNG project, Barcarena Power Plant, and PortoCem Power Plant. Such borrowings were also used to repay a portion of the 2025 Notes and various asset level financings in Puerto Rico and Brazil. We also repaid our Revolving Facility and short-term borrowings under repurchase agreements, prior to again drawing on these facilities.

Our cash flow provided by financing activities during the year ended December 31, 2023 included a dividend payment of $626.3 million that was made in January 2023. We have borrowed under our new Term Loan B Agreement, expanded Revolving Facility, Bridge Term Loans, Equipment Notes, Barcarena Debentures, EB-5 Loan, Tugboat Financing, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $3.0 billion. Such borrowings were primarily used to fund the ongoing development of our Fast LNG project and to support our grid stabilization project in Puerto Rico. Increased borrowings during 2023 were offset by repayments of debt totaling $686.5 million, primarily the repayment of the Bridge Term Loans and short-term borrowings under repurchase arrangements.

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Long-Term Debt

2024 Exchange Transactions

On November 6, 2024, we entered into an exchange and subscription agreement (the “Exchange and Subscription Agreement”) with certain holders (the “Supporting Holders”) of our outstanding 2026 Notes and 2029 Notes (each defined below). Pursuant to the Exchange and Subscription Agreement (i) NFE Financing LLC (“NFE Financing”), an indirect subsidiary of NFE, sold to the Supporting Holders approximately $1,210.4 million aggregate principal amount of NFE Financing’s 12.0% Senior Secured Notes due 2029 (the “New 2029 Notes”) (the transactions described in clause (i), the “Subscription Transactions”) and (ii) NFE Financing issued to the Supporting Holders approximately $1,519.7 million aggregate principal amount of New 2029 Notes in a dollar-for-dollar exchange for a portion of our 2026 Notes and 2029 Notes (the transactions described in clause (ii), the “Exchange Transactions” and together with the Subscription Transactions, the “Refinancing Transactions”).

NFE Financing issued $2,730.1 million aggregate principal amount of New 2029 Notes pursuant to the Refinancing Transactions. We utilized $886.6 million of these net proceeds from the Subscription Transactions to repay in full the outstanding aggregate principal amount and accrued interest on the 2025 Notes. The remainder of the net proceeds from the New 2029 Notes issued pursuant to the Subscription Transactions will be used for general corporate purposes.

Pursuant to the Exchange and Subscription Agreement, upon consummation of the Refinancing Transactions, the Supporting Holders received a commitment fee equal to either (i) 5% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in shares of Class A common stock of the Company, at a price of $8.63 per share (the “Commitment Fee Shares”), (ii) 2% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in kind in the form of additional New 2029 Notes (the “Commitment Fee Notes”), or (iii) a combination of the foregoing. We have issued 15,700,998 Commitment Fee Shares to the Supporting Holders in satisfaction of its commitment fee obligations under the Exchange and Subscription Agreement, and $5.4 million Commitment Fee Notes were issued and included in the total New 2029 Notes issuance.

The New 2029 Notes were issued pursuant to, and are governed by, an indenture (the “New Notes Indenture”). The New 2029 Notes are senior, secured obligations of NFE Financing, and interest is payable semi-annually in arrears at a rate of 12.0% per annum on May 15 and November 15 of each year, beginning on May 15, 2025. The New Notes will mature on November 15, 2029, provided that the maturity date shall be accelerated to the date that is 91 days prior to the stated maturity date of any of our other indebtedness, subject to certain exceptions as described in the New Notes Indenture, if more than $100.0 million aggregate principal amount of such other indebtedness remains outstanding on such date.

NFE Financing may redeem some or all of the New 2029 Notes at redemption prices set forth in the New Notes Indenture; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. Further, upon the occurrence of certain other events, including change of control and certain distributions from our Brazil business, NFE Financing may be required to make an offer to repurchase all of the New 2029 Notes at prices specified in the New Notes Indenture.

The New 2029 Notes are guaranteed by NFE Financing’s wholly-owned subsidiary, Bradford County Real Estate Partners LLC (the “New Notes Guarantor”) which owns our land in Wyalusing, Pennsylvania. The New 2029 Notes are secured by first-priority liens on: (a) all assets of NFE Financing, including approximately 45% of the equity in the entity that owns our Brazil business, and 100% of the equity in the New Notes Guarantor and (b) all assets of the New Notes Guarantor.

The New Notes Indenture provides for customary events of default which include (subject in certain cases to customary grace and cure periods), among others, acceleration and/or defaults of certain of our other indebtedness. The New Notes Indenture and other credit agreements associated with certain intercompany loans of NFE Financing, limit our ability to, among other things, incur additional indebtedness, incur liens that secure indebtedness, make restricted payments, create dividend restrictions and other payment restrictions, sell or transfer certain assets, in each case subject to certain exceptions and qualifications set forth in the New Notes Indenture and other indentures.

The repayment of all of the 2025 Notes and the exchange of a portion of the 2026 Notes and 2029 Notes was treated as an extinguishment, and $11.4 million of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Fees paid to lenders, including the issuance of Commitment Fee Shares and Commitment Fee Notes, of $193.4 million were included in

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the loss on extinguishment of debt. We also recognized $30.5 million of loss on extinguishment of debt, which represents the fair value of the New 2029 Notes issued in excess of the carrying amount of debt exchanged or repaid. The New 2029 Notes are recorded at fair value and fees paid to third parties of $32.3 million will be amortized over the term of the New 2029 Notes.

In conjunction with the Refinancing Transactions, the Supporting Holders agreed to consent to certain amendments to the indentures pursuant to which the 2026 Notes (such indenture, the “Existing 2026 Notes Indenture”) and the 2029 Notes (such indenture, the “Existing 2029 Notes Indenture”) were issued. These amendments allow us to subordinate the liens on certain of the collateral securing the obligations under each of the Existing 2026 Notes Indenture and Existing 2029 Notes Indenture to the liens on the same collateral securing certain intercompany loans due to NFE Financing, and to remove all covenants and events of default that may be removed in compliance with terms of such indentures (the “Indenture Amendments”). The adoption of the Indenture Amendments required the consent of holders of at least 66.67% the outstanding principal amount of each of the 2026 Notes and 2029 Notes. We received the required level of consent, and subsequently executed a supplemental indenture to the Existing 2026 Notes Indenture (the “2026 Supplemental Indenture”) and a supplemental indenture to the Existing 2029 Notes Indenture (the “2029 Supplemental Indenture,” and, together with the 2026 Supplemental Indenture, the “Supplemental Indentures”) effecting the Amendments. The Supplemental Indentures became effective on December 5, 2024.

Series I Credit Agreement

On November 22, 2024, NFE Brazil Investments LLC (“Brazil Parent”), as lender, Wilmington Savings Fund Society, FSB, as the administrative agent and as collateral agent, New Fortress Energy Inc. , as borrower, and certain subsidiaries, as guarantors, entered into a senior secured, multiple-draw term loan credit agreement (“Series I Credit Agreement”) in an aggregate principal amount of approximately $970.0 million (the “Series I Term Loan Facility,” and the loans made under the Series I Term Loan Facility, the “Series I Term Loans”). The initial and subsequent funding of the Series I Term Loans are subject to certain customary conditions. The Series I Term Loans bear interest at a rate of 16.5997% (exclusive of 2.00% interest being paid-in-kind) per annum, payable semiannually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025. The cash interest rate on the Series I Term Loans will be reduced by an amount to be determined from and after the closing date of the Refinancing Transactions. On November 22, 2024, NFE borrowed $875.0 million of Series I Term Loans to redeem in full the outstanding aggregate principal amount of the 2025 Notes. On December 6, 2024, NFE borrowed the remaining $95.0 million of the Series I Term Loans, the proceeds of which were used to effectuate the transactions contemplated by the Exchange and Subscription Agreement.

The Series I Term Loans will mature on November 15, 2029 and will be payable in full on the maturity date. The obligations under the Series I Credit Agreement are guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes and the 2029 Notes. The obligations under the Series I Credit Agreement are secured by substantially the same collateral as the collateral securing the 2026 Notes and the 2029 Notes. An equal priority intercreditor agreement governs the treatment of the collateral.

The Series I Term Loans may be voluntarily prepaid by NFE, in whole or in part, subject to prepayment premiums, as set forth in the Series I Credit Agreement; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. NFE will be required to prepay the Series I Term Loans upon the occurrence of any change of control (which shall include any change of control as defined in the New Notes Indenture and the Brazil Parent Credit Agreement), and with the net proceeds of certain asset sales, condemnations and debt and convertible securities issuances.

The Series I Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Brazil Parent Credit Agreement

On November 22, 2024, NFE Financing, as lender, entered into a credit agreement (the “Brazil Parent Credit Agreement”), with Brazil Parent, as the borrower, and Wilmington Savings Fund Society, FSB, as administrative agent and collateral agent.

The Brazil Parent Credit Agreement provides for a senior secured, multiple-draw term loan facility of approximately $970.0 million (the “Brazil Parent Term Loan Facility,” and the term loans made thereunder, the “Brazil Parent Term Loans”), which matures on November 15, 2029. The stated maturity date will be accelerated to a date that is 91 days prior to the stated maturity date of any other indebtedness for borrowed money (including indebtedness deemed issued in a debt

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exchange), excluding indebtedness under the amended uncommitted letter of credit and reimbursement agreement, if more than $100.0 million in aggregate principal amount of such indebtedness remains outstanding at such time. The initial and subsequent funding of the Brazil Parent Term Loans are subject to certain customary conditions. The Brazil Parent Term Loans bear interest at a rate of 16.5997% (exclusive of 2.00% interest being paid-in-kind) per annum, payable semiannually in arrears on May 15 and November 15 of each year, beginning on May 15, 2025. The cash interest rate on the Brazil Parent Term Loans will be reduced by an amount to be determined from and after the closing of the Refinancing Transactions. The obligations under the Brazil Parent Credit Agreement are secured by substantially all assets of Brazil Parent (including a pledge of the equity interests held by Brazil Parent in NFE Brazil Holdings). On November 22, 2024, Brazil Parent borrowed $875.0 million of Brazil Parent Term Loans, the proceeds of which were advanced to us pursuant to the Series I Credit Agreement for the redemption in full of the outstanding aggregate principal amount of the 2025 Notes. On December 6, 2024, Brazil Parent borrowed the remaining $95.0 million from the Brazil Parent Term Facility. The proceeds of the Brazil Parent Term Loan were used to fund the Series I Term Loan Facility.

The Brazil Parent Term Loans may be voluntarily prepaid by Brazil Parent, subject to prepayment premiums as set forth in the Brazil Parent Credit Agreement; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. In addition, Brazil Parent will be required to prepay the Brazil Parent Term Loans upon the occurrence of certain events (subject to certain premiums as applicable and set forth in the Brazil Parent Credit Agreement), including any change of control and receipt of net proceeds from any prepayment under the Series I Credit Agreement.

The Brazil Parent Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Series II Credit Agreement

On December 6, 2024, NFE Financing, as lender, Wilmington Savings Fund Society, FSB, as the administrative agent and as collateral agent, and NFE, as borrower, and certain of our subsidiaries of NFE from time to time party thereto as guarantors, entered into a senior secured term loan credit agreement (“Series II Credit Agreement,” and together with the Series I Credit Agreement and the Brazil Parent Credit Agreement, the “Intercompany Credit Agreements”) in an aggregate principal amount of approximately $1.43 billion (the loan made under the term loan facility, the “Series II Term Loan”). The proceeds will be used by us to consummate the transactions contemplated by the Exchange and Subscription Agreement.

The Series II Term Loan will mature in November 2029 and is payable in full on the maturity date. The obligations under the Series II Credit Agreement will be guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes and the 2029 Notes. The obligations under the Series II Credit Agreement will be secured by substantially the same collateral as the collateral securing the 2026 Notes and the 2029 Notes. An equal priority intercreditor agreement will govern the treatment of the collateral.

The Series II Term Loans may be voluntarily prepaid by NFE, in whole or in part, subject to prepayment premiums, as set forth in the Series II Credit Agreement; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. NFE will be required to prepay the Series II Term Loan upon the occurrence of any change of control (which shall include any change of control as defined in the New Notes Indenture and the Brazil Parent Credit Agreement), and with the net proceeds of certain asset sales, condemnations and debt and convertible securities issuances.

The Series II Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

2025 Notes

In September and December 2020, we issued an aggregate amount of $1,250.0 million of 6.75% senior secured notes in private offerings pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest was payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments were due until maturity on September 15, 2025.

In connection with the offering of the 2029 Notes (defined below) in March 2024, 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

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the repurchase price of $1.9 million was recognized as Loss on extinguishment of debt, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The remaining outstanding principal under the 2025 Notes was repaid in conjunction with the Refinancing Transactions.

2026 Notes

In April 2021, we issued $1,500.0 million of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of each year; no principal payments are due until maturity on September 30, 2026. We may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2026 Notes are guaranteed, jointly and severally, on a senior secured basis by certain domestic and foreign subsidiaries. Subsequent to the Refinancing Transactions, the 2026 Notes are subject to the 2026 Supplemental Indenture.

2029 Notes

In March 2024, we issued $750.0 million of 8.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2029 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments are due until maturity on March 15, 2029. We may redeem the 2029 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2029 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2026 Notes. Subsequent to the Refinancing Transactions, the 2029 Notes are subject to the 2029 Supplemental Indenture.

Revolving Facility

In April 2021, we entered into a credit agreement (the "Revolving Credit Agreement") for a $200.0 million senior secured revolving credit facility (the "Revolving Facility"). Through December 31, 2023, the Revolving Facility was amended to increase the borrowing capacity to $950.0 million. In May 2024, we entered into an amendment which increased the borrowing capacity by $50.0 million, for a total capacity of $1,000.0 million. The amendments did not impact the interest rate or term of the Revolving Facility, and no deferred costs were written off. As of December 31, 2024 and 2023, $1,000.0 million and $866.6 million was outstanding under the Revolving Facility.

The borrowings under the Revolving Facility bear interest at a Secured Overnight Financing Rate ("SOFR") based rate plus a margin based upon usage of the Revolving Facility. The rates applicable to outstanding borrowings as of December 31, 2024 and 2023 were 8.22% and 8.29%, respectively. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium.

Concurrent with the Refinancing Transactions, we entered into an amendment with certain lenders in the Revolving Facility (the "Consenting Lenders") to extend the maturity of their commitments to October 15, 2027. The Consenting Lenders hold $900.0 million of the total revolving commitments. The applicable margin payable on revolving borrowings to the Consenting Lenders increased by 100 basis points. We are required to reduce the commitments with proceeds from certain assets sales and by certain amounts received from the settlement of our claims following the termination of our contract to provide emergency power services in Puerto Rico (Note 5). Notwithstanding these required reductions, we must reduce commitments for Consenting Lenders to $630.0 million by September 30, 2025, and as such, $270.0 million of the outstanding borrowings under the Revolving Facility have been recognized as current. The remainder of the Revolving Facility will mature in April 2026 with the potential for us to extend the maturity date once for a one-year increment.

The obligations under the Revolving Facility are guaranteed by certain of our subsidiaries, including those that own our offshore FLNG facility at Altamira ("FLNG1 Project") and Altamira Onshore Project (defined below), and are secured by substantially the same collateral securing the obligations under certain intercompany loans entered into in conjunction with the Refinancing Transactions, as well as the assets comprising the FLNG1 Project and Altamira Onshore Project. We are required to comply with the below covenants under the Revolving Facility and Letter of Credit Facility (defined below):

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ending March 31, 2025, (ii) 7.25 to 1.00, for the fiscal quarter ending June 30, 2025, (iii) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (iv) 6.50 to 1.00, for the fiscal quarter ending December 31, 2025, (v) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 through September 30, 2026, and (vi) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter.

•Beginning with fiscal quarter ended March 31, 2025, the Fixed Charge Coverage Ratio must be less than or equal to (i) 0.80 to 1.00, for the fiscal quarter ending March 31, 2025 and (ii) 1.00 to 1.00, for the fiscal quarter ending June 30, 2025 and each fiscal quarter thereafter.

•We are also required to maintain a minimum consolidated liquidity of (i) $50,000 as of the last day of each month, commencing as of October 31, 2024 and (ii) $100,000 as of the last day of any fiscal quarter, commencing as of December 31, 2024. We were in compliance with these covenants as of December 31, 2024.

The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

Letter of Credit Facility

In July 2021, we entered into an uncommitted letter of credit and reimbursement agreement (the "Letter of Credit Agreement") with a bank for the issuance of letters of credit for an aggregate amount of up to $75.0 million (the“Letter of Credit Facility”). Through December 31, 2023, the Letter of Credit Facility was amended multiple times to increase the availability to $350.0 million. As of December 31, 2024, the Letter of Credit Facility had a limit of $315,000, and the outstanding letters of credt have an interest rate of 3.35%. We had an unutilized Letter of Credit Facility balance of $69.0 million as at December 31, 2024

Term Loan B Credit Agreement

On August 3, 2023, we entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) in an aggregate principal amount of $400.0 million. The Bridge Term Loans were initially set to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%.

On October 30, 2023, we entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to in an aggregate principal amount of $856.0 million ("Term Loan B"). Borrowings were issued at a discount, and we received proceeds of $787.5 million. The proceeds from the Term Loan B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature on the earliest of (i) October 30, 2028 if the 2026 Notes are refinanced in full prior to their maturity and (ii) July 31, 2026, if any of the 2026 Notes remain outstanding as of such date. Quarterly principal payments of approximately $2.1 million are required beginning March 2024.

The obligations under the Term Loan B are guaranteed by certain of our subsidiaries, including those that own our FLNG1 Project and Altamira Onshore Project (defined below). The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2026 Notes, the Revolving Facility, and, in addition, is secured by assets compromising our FLNG1 Project.

The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. We may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. We are required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, we will be required to prepay the Term Loan B with our Excess Cash Flow (as defined in the Term Loan B Agreement).

The Term Loan B 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 Agreement.

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Term Loan A Credit Agreement

In July 2024, we entered into a credit agreement ("Term Loan A Credit Agreement") for a senior secured, multiple draw term loan facility in an aggregate principal amount of up to $700.0 million ("Term Loan A"). Proceeds must be used to pay costs of the construction and development of our onshore FLNG project in Altamira (the “Altamira Onshore Project”). During the year ended December 31, 2024, we drew $350.0 million on the Term Loan A. The remaining commitments for subsequent funding expire on the earliest of June 30, 2026, the date of completion of the Onshore Altamira Project (the “Completion Date”) and the date that the commitments are reduced to zero or terminated.

The obligations under the Term Loan A Credit Agreement are guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes, 2029 Notes, our Revolving Facility, our letter of credit facility (the “Letter of Credit Facility”) and our Term Loan B, other than the guarantors comprising the FLNG1 Project (who guarantee the Revolving Facility, the Letter of Credit Facility, and the Term Loan B). The obligations under the Term Loan A Credit Agreement are secured by substantially the same collateral as the collateral securing such facilities, with the exception of the collateral comprising the FLNG1 Project (which secures the Revolving Facility, the Letter of Credit Facility, and the Term Loan B). Additionally, the Term Loan A is guaranteed by the entities, and secured by the assets, comprising the Onshore Altamira Project. An equal priority intercreditor agreement governs the treatment of the collateral.

The Term Loan A will mature in July 2027 and is payable in full on the maturity date. In the event that our existing 2026 Notes are not refinanced or repaid at least 60 days prior to maturity, amounts outstanding under the Term Loan A will become due and payable on such date. We may prepay the Term Loan A at its option without premium or penalty at any time subject to customary break funding costs. We are required to prepay the Term Loan A with the net proceeds of certain asset sales, condemnations, debt and convertible securities issuances, and extraordinary receipts related to the Onshore Altamira Project. Additionally, commencing with the first fiscal quarter after the Completion Date, we will be required to prepay the Term Loan A with the Onshore Altamira Project’s Excess Cash Flow (as defined in the Term Loan A Credit Agreement).

The Term Loan A will bear interest at a per annum rate equal to Term SOFR plus 3.75%, or at a base rate plus 2.75%. The interest rate on the Term Loan A will increase by 0.25% every 180 days beginning on June 30, 2025.

The Term Loan A Credit Agreement contains usual and customary representations, warranties and affirmative and negative covenants for financings of this type, including certain representations and warranties related to the Onshore Altamira Project. The Term Loan A Credit Agreement includes certain other covenants related solely to the Onshore Altamira Project, including limitations on capital expenditures, restrictions on additional accounts, and restrictions on amendments or termination of certain material documents related to the Onshore Altamira Project. We must also comply with certain financial covenants consistent with those under the Revolving Facility, including Debt to EBITDA Ratio and minimum consolidated liquidity.

Short-term Borrowings

We may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2024, we had $179.9 million due under these arrangements.

Vessel Financing Obligation

In connection with of the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to us at the time of closing were classified as finance leases. Additionally, our charter of certain other vessels will commence only upon the expiration of the vessel's existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, we accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation for consideration received.

We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we recognize revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation;

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at inception of the arrangement, the effective interest rate on this financing obligation was approximately 15.9% and includes the cash flows that Energos receives from these third-party charters. Charter payments due in 2025 include $57.8 million that will be treated as a payment of principal, and this amount is included within the current portion of long-term debt.

Tugboat Financing

In December 2023, we sold and leased back four tugboat vessels for 15 years receiving proceeds of $46.7 million. ("Tugboat Financing"). The leasebacks of the tugboat vessels were classified as finance leases, and as such, we accounted for the Tugboat Financing as a failed sale-leaseback and has recorded a financing obligation for consideration received. The effective interest rate on this financing obligation is approximately 16.92%.

PortoCem Financings

As part of the PortoCem Acquisition, we assumed a term loan in the aggregate principal amount of R$141,445 million ($28.1 million based on the exchange rate 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 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 borrowed R$1.5 billion, and this 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 bore interest at the one-day interbank deposit futures rate in Brazil plus 4.25%, and no principal payments were required until maturity in October 2025.

In November 2024, PortoCem issued R$4.5 billion ($726.8 million based on exchange rates in effect at December 31, 2024) of debentures to BNDES ("PortoCem Debentures"). Borrowings bear interest at 9.15%. No principal or interest payments are due until September 2027; at that point, PortoCem will begin to make semi-annual payments until maturity in September 2040. Proceeds received were utilized to repay the PortoCem Bridge Loan, and the remaining proceeds are restricted to fund the construction of the PortoCem Power Plant.

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.

Barcarena Financings

In October 2023, certain of our Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of our power plant located in Pará, Brazil (the "Barcarena Power Plant"). The parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures") and issued $180 million of the Barcarena Debentures prior to December 31, 2023. The remaining series may be issued upon the achievement of certain conditions precedent. Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12.0%, increasing 1.25% each year after the third anniversary of issuance. We are able to prepay the Barcarena Debentures, subject to certain make whole penalties, and we are required to utilize certain excess cash flows from our Brazilian operations to prepay principal.

The Barcarena Debentures are convertible into shares of one of our indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.

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required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.

The owner of 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"). We borrowed $344.7 million under the BNDES Credit Agreement in 2024. Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045. Interest payments prior to April 2026 are made through an increase in the outstanding principal amount and are due quarterly thereafter.

The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's PPAs. 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.

South Power 2029 Bonds

In January 2022, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into an agreement for the issuance of up to $285.0 million secured bonds (“South Power 2029 Bonds”). The South Power 2029 Bonds are secured by, amongst other things, our combined heat and power plant in Clarendon, Jamaica (“CHP Plant”), and NFE has provided a guarantee of the obligations under the South Power 2029 Bonds. As of both December 31, 2024 and 2023, South Power had $221.8 million of South Power 2029 Bonds issued and outstanding.

The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.

South Power is required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provide for customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2024 and 2023.

Turbine Financing

In May 2024, we executed a loan agreement with a lender to borrow $148.5 million under a promissory note secured by certain turbines owned by a wholly-owned subsidiary of ours (the “Turbine Financing”). The Turbine Financing bears interest at 10.30%, and the principal is partially repayable in monthly installments over the 36-month term of the loan with the balance due upon maturity in June 2027.

The Turbine Financing contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Turbine Financing does not contain any restrictive financial covenants. We were required to pay a deposit of approximately $6.0 million that will be held by the lender throughout the term of the borrowing recorded in Other non-current assets, net

EB-5 Loan Agreement

On July 21, 2023, we entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100.0 million, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE's green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the year ended December 31, 2023, $62.9 million was funded under the EB-5 Loan Agreement, and the remaining availability of $37.1 million was funded during the year ended December 31, 2024.

The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants.

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Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. We evaluate our estimates and related assumptions regularly, and we believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.

Impairment of long-lived assets

We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract, or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.

Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.

Geopolitical and other macroeconomic events can substantially impact natural gas and LNG markets, leading to volatility in market pricing. The majority of our LNG supply contracts are based on a natural gas-based index, Henry Hub, plus a contractual spread. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. 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 contractual spread. Based on the long-term nature of our supply and customer contracts, the nature of the pricing in these contracts and the market value of our underlying assets, changes in the price of natural gas or LNG do not indicate that a recoverability assessment of our assets is necessary. Further, LNG production from our own FLNG facilities will further mitigate our exposure to variability in LNG and natural gas prices.

When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. We develop the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.

Recent Accounting Standards

For descriptions of recently issued accounting standards, refer to “Note 3. Adoption of new and revised standards” of our notes to consolidated financial statements included in this Annual Report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risks.

In the normal course of business, we encounter several significant types of market risks including commodity and interest rate risks.

Commodity Price Risk

Commodity price risk is the risk of loss arising from adverse changes in market rates and prices. Our exposure to market risk associated with LNG price changes may adversely impact our business. We are able to limit our exposure to fluctuations in natural gas prices as our pricing in contracts with downstream customers is largely based on the Henry Hub

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index price plus a contractual spread. We currently do not have any derivative instruments to mitigate the effect of fluctuations in LNG prices on our operations; however, in the future we may enter into derivative instruments.

Interest Rate Risk

The 2026 Notes, 2029 Notes, New 2029 Notes, South Power 2029 Bonds, Barcarena Debentures, EB-5 Loan, Portocem Debentures and Turbine Financing (each defined above or in the Annual Report) were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the debt outstanding but such a change would have no impact on our results of operations or cash flows. A 100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $143 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve.

Interest under the Term Loan A and Term Loan B have components based on the Secured Overnight Financing Rate ("SOFR"), and the BNDES Term Loan has components based on BNDES fixed rate. A 100-basis point increase or decrease in the market interest rates would decrease or increase our annual interest expense by approximately $16 million.

Foreign Currency Exchange Risk

We have transactions, assets and liabilities denominated in Brazilian reais, and our Brazilian subsidiaries and investments receive income and pay expenses in Brazilian reais. Based on our Brazilian reais revenues and expenses, a 10% depreciation of the U.S. dollar against the Brazilian reais would not significantly decrease our revenue or expenses. As our operations expand in Brazil, our results of operations will be exposed to changes in fluctuations in the Brazilian real, which may materially impact our results of operations. During 2024, we entered into a series of foreign exchange forward contracts and zero-cost collar options to reduce exchange rate risk associated with U.S. dollar borrowings and expected capital expenditures. As of December 31, 2024, the notional amount of outstanding foreign exchange contracts was approximately $211.5 million.

Outside of Brazil, our operations are primarily conducted in U.S. dollars, and as such, our results of operations and cash flows have not materially been impacted by fluctuations due to changes in foreign currency exchange rates. We currently incur a limited amount of costs in foreign jurisdictions other than Brazil that are paid in local currencies. As we expect our international operations to continue to grow in the near term, we may enter into derivative or hedging transactions with third parties to manage our exposure to changes in foreign currency exchange risks as we expand our international operations.

Item 8. Financial Statements and Supplementary Data.

Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this Annual Report and are incorporated herein by reference.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Securities Exchange Act of 1934, as amended ("Exchange Act"), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2024. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2024 at the reasonable assurance level.

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Changes in Internal Control over Financial Reporting

There has been no change in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2024 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

As of December 31, 2024, our management assessed the effectiveness of our internal control over financial reporting based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control – Integrated Framework (2013).” Based on this assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2024.

The effectiveness of our internal control over financial reporting as of December 31, 2024 has been audited by EY, an independent registered public accounting firm, as stated in their report, which appears herein.

Item 9B. Other Information.

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

None.

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Part III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by this Item 10 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2024 in connection with our 2025 annual meeting of shareholders (the “2025 Proxy Statement”) under the heading “Proposal No. 1 Election of Directors,” the subheadings “Information Concerning Our Directors, Including the Director Nominees,” “Insider Trading Policies and Procedures,” “Code of Conduct” and “The Board and its Committees—Audit Committee,” and the headings “Management” and if applicable, “Security Ownership of Management and Certain Beneficial Owners—Delinquent Section 16(a) Reports” and is incorporated herein by reference.

Item 11. Executive Compensation

The information required by this Item 11 is set forth in the Company’s 2025 Proxy Statement under the headings “Executive Compensation” (other than the information under the subheading “Pay Versus Performance”), “Compensation Committee Report” and “Director Compensation” and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.

The information required by this Item 12 is set forth in the Company’s 2025 Proxy Statement under the headings “Equity Compensation Plan Information” and “Security Ownership of Management and Certain Beneficial Owners” and is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by this Item 13 is set forth in the Company’s 2025 Proxy Statement under the headings “Certain Relationships and Related Transactions” and “Proposal No. 1 Election of Directors—Determination of Director Independence” and is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services.

The information required by this Item 14 is set forth in the Company’s 2025 Proxy Statement under the heading “Proposal No. 2 Approval of Appointment of Ernst & Young LLP as Independent Registered Public Accounting Firm—Principal Accountant Fees and Services” and is incorporated herein by reference.

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Part IV

Item 15. Exhibits, Financial Statement Schedules.

The financial statements of New Fortress Energy Inc. and consolidated subsidiaries are included in Item 8 of this Form 10-K (Form 10-K). Refer to “Index to Financial Statements” set forth of page F-1.

The report of New Fortress Energy’s independent registered public accounting firm (PCAOB ID:#42) with respect to the above-referenced financial statements and their report on internal control over financial reporting are included in Item 8 and Item 9A of this Form 10-K at the page numbers F-2 and F-4, respectively. Their consent appears as Exhibit 23.1 of this Form 10-K.

(2) Financial Statement Schedule.

See Schedule II set forth on page F-61.

(b) Exhibits.

The exhibits required to be filed by this Item 15(b) are set forth in the Exhibit Index included below.


Exhibit Number			Description

3.1			Certificate of Conversion of New Fortress Energy Inc. (incorporated by reference to Exhibit 99.2 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2020).

3.2			Certificate of Incorporation of New Fortress Energy Inc. (incorporated by reference to Exhibit 99.3 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2020).

3.3			Certificate of Designations of New Fortress Energy Inc., designating the Company’s 4.8% Series A Convertible Preferred Stock, par value $0.01 per share (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on March 26, 2024).

3.4			Certificate of Designations of New Fortress Energy Inc., designating the Company's 4.8% Series B Convertible Preferred Stock, par value $0.01 per share (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K, filed with the SEC on October 2, 2024).

3.5			Bylaws of New Fortress Energy Inc. (incorporated by reference to Exhibit 99.4 to the Registrant’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2020).

10.1†			Form of Director Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A, filed with the SEC on December 24, 2018).

10.2†			Restricted Share Unit Award Agreement under the Amended and Restated New Fortress Energy Inc. 2019 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q, filed with the Commission on November 8, 2022).

10.3			Shareholders’ Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and Randal A. Nardone (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.4			Administrative Services Agreement, dated February 4, 2019, by and between New Fortress Intermediate LLC and FIG LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

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10.5†			Indemnification Agreement (Edens) (incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.6†			Indemnification Agreement (Guinta) (incorporated by reference to Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.7†			Indemnification Agreement (Catterall) (incorporated by reference to Exhibit 10.7 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.8†			Indemnification Agreement (Grain) (incorporated by reference to Exhibit 10.8 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.9†			Indemnification Agreement (Griffin) (incorporated by reference to Exhibit 10.9 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.10†			Indemnification Agreement (Mack) (incorporated by reference to Exhibit 10.10 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.11†			Indemnification Agreement (Nardone) (incorporated by reference to Exhibit 10.11 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.12†			Indemnification Agreement (Wanner) (incorporated by reference to Exhibit 10.12 to the Registrant’s Current Report on Form 8-K, filed with the SEC on February 5, 2019).

10.13†			Indemnification Agreement (Jay) (incorporated by reference to Exhibit 10.15 to the Registrant's Quarterly Report on Form 10-Q, filed with the SEC on May 4, 2023).

10.14†			Indemnification Agreement, dated as of March 17, 2019, by and between New Fortress Energy LLC and Yunyoung Shin (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019).

10.15			Letter Agreement, dated as of December 3, 2019, by and between NFE Management LLC and Yunyoung Shin (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2020).

10.16			Letter Agreement, dated as of March 14, 2017, by and between NFE Management LLC and Christopher S. Guinta (incorporated by reference to Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.17			Indenture, dated April 12, 2021, by and among the Company, an issuer, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021).

10.18			Pledge and Security Agreement, dated April 12, 2021, by and among the Company, the subsidiary guarantors, from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021).

10.19			First Supplemental Indenture, dated as of June 11, 2021, between Golar GP LLC (now known as NFE GP LLC), as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

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10.20			Second Supplemental Indenture, dated as of September 13, 2021, between NFE Mexico Power Holdings Limited and NFE Mexico Terminal Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.21			Third Supplemental Indenture, dated as of November 24, 2021, between NFE International Shipping LLC, NFE Global Shipping LLC, NFE Grand Shipping LLC and NFE International Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.31 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.22			Fourth Supplemental Indenture, dated as of March 23, 2022, between NFE UK Holdings Limited, NFE Global Holdings Limited and NFE Bermuda Holdings Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.32 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.23			Fifth Supplemental Indenture, dated as of December 22, 2022, between NFE Andromeda Chartering LLC, as Guaranteeing Subsidiary, and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee (incorporated by reference to Exhibit 10.33 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.24*			Sixth Supplemental Indenture, dated as of October 18, 2024, between NFE International Holdings 1 Limited and NFE International Holdings 1 Limited (each a “Guaranteeing Subsidiary”) as Guaranteeing Subsidiaries and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association).

10.25*			Seventh Supplemental Indenture, dated as of December 5, 2024, between the various Guaranteeing Subsidiaries party thereto and U.S. Bank Trust Company, National Association (as successor in interest to U.S. Bank National Association), as trustee.

10.26			Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc,. as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021).

10.27			First amendment to Credit Agreement, dated as of July 16, 2021 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time partly thereto, the several lenders and issuing banks from time to time partly thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2022).

10.28			Second Amendment to Credit Agreement, dated as of February 28, 2022 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.31 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2022).

10.29			Third Amendment to Credit Agreement, dated as of May 4, 2022 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.32 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2022).

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10.30			Fourth Amendment to Credit Agreement, dated as of February 7, 2023 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.38 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.31			Fifth Amendment to Credit Agreement, dated as of September 15, 2023 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.39 to the Registrant's Annual Report on Form 10-Q, filed with the SEC on November 9, 2023).

10.32			Sixth Amendment to Credit Agreement, dated as of December 18, 2023 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.40 to the Registrant's Annual Report on Form 10-K, filed with the SEC on February 29, 2024).

10.33			Seventh Amendment to Credit Agreement, dated as of May 3, 2024 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent. (incorporated by reference to Exhibit 10.41 to the Registrant's Quarterly Report on Form 10-Q, filed with the SEC on August 9, 2024).

10.34			Amended and Restated Eighth Amendment to Credit Agreement, dated as of September 30, 2024 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.42 to the Registrant's Quarterly Report on Form 10-Q, filed with the SEC on November 12, 2024).

10.35*			Ninth Amendment to Credit Agreement, dated as of November 6, 2024 to the Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent.

10.36*			Tenth Amendment to Credit Agreement, dated as of November 22, 2024 to the Credit agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and MUFG Bank Ltd., as administrative agent and collateral agent.

10.37			Equity Purchase and Contribution Agreement, dated as of July 2, 2022, by and among Golar LNG Partners LP and Hygo Energy Transition Ltd., as Sellers, AP Neptune Holdings Ltd, as Purchaser, Floating Infrastructure Holdings LLC, as the Company, and Floating Infrastructure Intermediate LLC, as Holdco Pledgor, and Floating Infrastructure Holdings finance LLC, as Borrower, and New Fortress Energy Inc.(incorporated by reference to Exhibit 10.39 to Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 5, 2022).

10.38			Uncommitted Letter of Credit and Reimbursement Agreement, dated as of July 16, 2021, by and among the Company, as borrower, each of the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent and as collateral agent.

10.39			Second Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated as of July 27, 2022 to the Uncommitted Letter of Credit and Reimbursement Agreement, dated as of July 16, 2021,, dated July 27, 2022, by and among the Company, as borrower, each of the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent and as collateral agent

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10.40			Incremental Joinder Agreement Regarding to Uncommitted Letter of Credit and Reimbursement Agreement, dated February 6, 2023, by and among the Company, as the borrower each of the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent (incorporated by reference to Exhibit 10.45 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 1, 2023).

10.41			Incremental Joinder Agreement Regarding to Uncommitted Letter of Credit and Reimbursement Agreement, dated November 2, 2023, by and among the Company, as borrower, each of the guarantors party thereto, the lenders and issuing bank party thereto and Natixis, New York Branch, as administrative agent (incorporated by reference to Exhibit 10.44 to the Registrant's Annual Report on Form 10-K, filed with the SEC on February 29, 2024).

10.42			Third Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated May 17, 2024, by and among the Company, as borrower, each of the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.46 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 9, 2024).

10.43			Fourth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated September 30, 2024, by and among the Company, the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.48 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on November 12, 2024).

10.44*			Fifth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated November 6, 2024, by and among the Company, the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent and as collateral agent.

10.45*			Sixth Amendment to Uncommitted Letter of Credit and Reimbursement Agreement, dated November 22, 2024, by and among the Company, the guarantors party thereto, the lenders and issuing banks party thereto and Natixis, New York Branch, as administrative agent and as collateral agent.

10.46			Credit Agreement, dated as of October 30, 2023, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders from time to time party thereto, and Morgan Stanley Senior Funding Inc., as administrative agent and collateral agent (incorporated by reference to Exhibit 10.45 to the Registrant's Annual Report on Form 10-K, filed with the SEC on February 29, 2024).

10.47			Indenture, dated March 8, 2024, by and among New Fortress Energy Inc., the subsidiary guarantors from time to time party thereto, and U.S. Bank Trust Company, National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on March 8, 2024).

10.48*			First Supplemental Indenture, dated as of October 18, 2024, between NFE International Holdings 1 Limited and NFE International Holdings 2 Limited, as Guaranteeing Subsidiaries, and U.S. Bank Trust Company, National Association, as trustee.

10.49*			Second Supplemental Indenture, dated as of December 5, 2024, by and among the Company, as issuer, by and among New Fortress Energy Inc., as issuer, the guarantors party thereto and U.S. Bank Trust Company, National Association, as trustee.

10.50			Pledge and Security Agreement, dated March 8, 2024, by and among the Company, the subsidiary guarantors, from time to time party thereto, and U.S. Bank Trust Company, National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on March 8, 2024).

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10.51			Credit Agreement, dated as of July 19, 2024, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders from time to time party thereto, and Morgan Stanley Senior Funding Inc., as administrative agent and collateral agent. (incorporated by reference to Exhibit 10.50 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on August 9, 2024).

10.52*			Amended and Restated First Amendment to Credit Agreement, dated as of September 30, 2024, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders from time to time party thereto, and Morgan Stanley Senior Funding Inc., as administrative agent and collateral agent.

10.53*			Second Amendment to Credit Agreement, dated as of November 14, 2024, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders from time to time party thereto, and Morgan Stanley Senior Funding Inc., as administrative agent and collateral agent.

10.54*			Third Amendment to Credit Agreement, dated as of November 22, 2024, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders from time to time party thereto, and Morgan Stanley Senior Funding Inc., as administrative agent and collateral agent.

10.55*			Series I Credit Agreement, dated as of November 22, 2024, among the Company, as the borrower, the guarantors from time to time party thereto, the lenders from time to time party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and collateral agent.

10.56*			Credit Agreement, dated as of November 22, 2024, among NFE Brazil Investments LLC, as the borrower, NFE Financing LLC, as lender, the lenders from time to time party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and collateral agent.

10.57*			Series II Credit Agreement, dated as of December 6, 2024, among the Company, as the borrower, the guarantors from time to time party thereto, the lenders from time to time party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and collateral agent.

10.58*			Transaction Support Agreement, dated as of September 30, 2024, by and among the Company and parties thereto.

10.59*			First Amendment to Transaction Support Agreement, dated as of November 4, 2024, by and among the Company and parties thereto.

10.60*			Second Amendment to Transaction Support Agreement, dated as of November 21, 2024, by and among the Company and parties thereto.

10.61*			Form of Exchange and Subscription Agreement, dated November 6, 2024, by and among the Company and parties thereto.

10.62*			Form of First Amendment to Exchange and Subscription Agreement, dated November 22, 2024, by and among the Company and parties thereto.

10.63*			Indenture, dated November 22, 2024, by and among NFE Financing LLC, as issuer, the guarantors from time to time party thereto, and Wilmington Savings Fund Society, FSB, as trustee.

10.64*			Registration Rights and Lock-up Agreement, dated as of December 6, 2024 by and among the Company and the undersigned investors.

10.65*			First Amendment to Registration Rights and Lock-up Agreement, dated as of January 8, 2025, by and among the Company and the undersigned investors.

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10.66*			Second Amendment to Registration Rights and Lock-up Agreement, dated as of February 4, 2025, by and among the Company and the undersigned investors.

19.1 *			New Fortress Energy Inc. Firmwide Insider Trading Policy

21.1*			List of Subsidiaries of New Fortress Energy Inc.

23.1*			Consent of Ernst & Young LLP, independent registered public accounting firm.

31.1*			Certification by Chief Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*			Certification by Chief Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) of the Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**			Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**			Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

97.1			Clawback Policy of the Company, effective as of December 1, 2023 (incorporated by reference from exhibit 97.1 to the Form 10-K dated February 29, 2024)

101.INS*			Inline XBRL Instance Document

101.SCH*			Inline XBRL Schema Document

101.CAL*			Inline XBRL Calculation Linkbase Document

101.LAB*			Inline XBRL Label Linkbase Document

101.PRE*			Inline XBRL Presentation Linkbase Document

101.DEF*			Inline XBRL Taxonomy Extension Definition Linkbase Document

104*			Cover Page Interactive Data File, formatted in Inline XBRL and contained in Exhibit 101

*Filed as an exhibit to this Annual Report

**Furnished as an exhibit to this Annual Report

† Compensatory plan or arrangement

# Portions of the exhibit (indicated by asterisks) have been omitted in pursuant to Item 601 (b)(10)(iv) of Regulation S-K.

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Item 16. Form 10-K Summary.

None.

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SIGNATURES

Pursuant to the requirements of 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	NEW FORTRESS ENERGY INC.
Date: March 10, 2025
	By:	/s/ Christopher Guinta
	Name:	Christopher S. Guinta
	Title:	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name

Title

Date

/s/ Wesley R. Edens

Chief Executive Officer and Chairman

(Principal Executive Officer)

March 10, 2025

Wesley R. Edens

/s/ Christopher S. Guinta

Chief Financial Officer

(Principal Financial Officer)

March 10, 2025

Christopher S. Guinta

/s/ Yunyoung Shin

Chief Accounting Officer

(Principal Accounting Officer)

March 10, 2025

Yunyoung Shin

/s/ Randal A. Nardone

Director

March 10, 2025

Randal A. Nardone

/s/ C. William Griffin

Director

March 10, 2025

C. William Griffin

Director

March 10, 2025

John J. Mack

/s/ Timothy W. Jay

Director

March 10, 2025

Timothy W. Jay

/s/ David J. Grain

Director

March 10, 2025

David J. Grain

/s/ Desmond Iain Catterall

Director

March 10, 2025

Desmond Iain Catterall

/s/ Katherine E. Wanner

Director

March 10, 2025

Katherine E. Wanner

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Index to Consolidated Financial Statements


			Page
Report of Independent Registered Public Accounting Firm (PCAOB ID: #42)			F-2
Consolidated Balance Sheets			F-6
Consolidated Statements of Operations and Comprehensive (Loss) Income			F-7
Consolidated Statements of Changes in Stockholders’ Equity			F-8
Consolidated Statements of Cash Flows			F-9
Notes to Consolidated Financial Statements			F-11

F-1

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of New Fortress Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of New Fortress Energy Inc. (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations and comprehensive (loss) income, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and financial statement schedule listed in the Index at Item 15(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 10, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

F-2

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						Impairment Assessment of Construction in Progress

Description of the Matter						As of December 31, 2024, the balance of construction in progress totaled $3,574 million. As described in Note 2(j) to the consolidated financial statements, the Company performs a recoverability assessment of all long-lived assets, including construction in progress, whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Impairment indicators affecting construction in progress asset groups may include, but are not limited to, factors such as adverse changes in the regulatory environment in a jurisdiction where the Company operates or has development activities, early termination of a significant customer contract, the introduction of newer technology, or a decision to discontinue an in-process development project. When such indicators are identified, management determines if asset groups are impaired by comparing the related undiscounted expected future cash flows to its carrying value. When the undiscounted cash flow analysis indicates an asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the asset group over its fair value. Auditing management’s determination of whether impairment indicators exist such that a recoverability test for a construction in progress asset group is required, was highly subjective and involved significant judgment. For instance, auditing management’s assessment of events or changes in circumstances that may be an indicator that an asset group is not recoverable was challenging due to the judgment applied in both the identification of such factors, and the evaluation of whether the factors have an impact on the recovery of the carrying value of the asset group.

How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s impairment assessment process. This included management’s controls to review for asset groups, including construction in progress, that may have been impacted by the impairment indicators described above. To test the Company’s evaluation of potential indicators of impairment of its construction in progress, our audit procedures included, among others, assessing the methodologies and testing the completeness and accuracy of the Company’s analysis of events or changes in circumstances. For example, we inquired of management (including project development personnel) to understand their evaluation of changes in the regulatory environments of the jurisdictions in which the Company has development projects and their impact on the completion of the construction in progress and recoverability of the related asset groups. We also obtained permits, contracts and project status reports, among other evidence, to understand management’s plans with respect to development activities. We considered information about the Company’s development projects from external sources that support or provide contrary evidence to management’s evaluation of potential impairment indicators.

F-3

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						Going concern

Description of the Matter						As discussed in Note 2(a) to the consolidated financial statements, management has concluded that the Company’s current liquidity and forecasted cash flows from operations are not sufficient to support, in full, its obligations as they become due. In response, management has developed a plan that it believes is probable of being implemented to enable the Company to meet its obligations as they become due during the period one year from the date the financial statements were issued. Auditing the Company’s assessment of its ability to continue as a going concern was especially challenging due to the significant judgment used by management in the development of the prospective financial information underlying its liquidity analysis including the estimation of forecasted cash flow that is not derived under long-term contractual arrangements, as well as in the assessment of whether management’s plans are probable of alleviating the Company’s liquidity risks.

How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design, and tested controls over the Company's going concern assessment process. For example, we tested controls over management's review of prospective financial information used in the liquidity analysis as well as its assessment of the likelihood of the timely implementation of its plans to support the Company’s liquidity position. To test the Company's assessment of its ability to continue as a going concern for the period of one year from the date the financial statements were issued, our audit procedures included, among others, evaluating the Company’s current liquidity and cash flows, and testing the completeness and accuracy of the data used in management’s assessment. We compared the assumptions underlying the contractual and noncontractual cash flow projections included in the prospective financial information used in management’s liquidity analysis to underlying agreements and historical operating results. Furthermore, we performed sensitivity analyses to assess the impact of changes in key assumptions included in management's prospective financial information and in its plans to support the Company’s liquidity position. We also assessed the sources of liquidity that the Company has available through inspection of executed financing arrangements, availability of financing for LNG cargo transactions through inspection of similar financing arrangements of marketplace participants and analysis of the Company’s history of successfully renewing such arrangements. In addition, we evaluated the adequacy of the Company’s financial statement disclosures.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2016.

Philadelphia, Pennsylvania

March 10, 2025

F-4

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Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of New Fortress Energy Inc.

Opinion on Internal Control Over Financial Reporting

We have audited New Fortress Energy Inc.’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, New Fortress Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2024 consolidated financial statements of the Company and our report dated March 10, 2025 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

March 10, 2025

F-5

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PART I

FINANCIAL INFORMATION

Item 8. Financial Statements

New Fortress Energy Inc.

Consolidated Balance Sheets

As of December 31, 2024 and 2023

(in thousands of U.S. dollars, except share and per share amounts)


	December 31, 2024		December 31, 2023
Assets
Current assets
Cash and cash equivalents	$	492,881	$	155,414
Restricted cash	472,696		155,400
Receivables, net of allowances of $13,629 and $1,158, respectively	335,813		342,371
Inventory	103,224		113,684
Prepaid expenses and other current assets, net	205,496		213,104
Total current assets	1,610,110		979,973


Construction in progress	3,574,389		5,348,294
Property, plant and equipment, net	5,842,807		2,481,415
Equity method investments	—		137,793
Right-of-use assets	618,733		588,385
Intangible assets, net	179,510		51,815

Goodwill	766,350		776,760
Deferred tax assets, net	2,698		9,907
Other non-current assets, net	272,899		126,903
Total assets	$	12,867,496	$	10,501,245

Liabilities
Current liabilities
Current portion of long-term debt and short-term borrowings	$	539,132	$	292,625
Accounts payable	473,736		549,489
Accrued liabilities	391,359		471,675
Current lease liabilities	128,362		164,548
Other current liabilities	174,829		227,951
Total current liabilities	1,707,418		1,706,288

Long-term debt	8,355,703		6,510,523
Non-current lease liabilities	475,161		406,494
Deferred tax liabilities, net	73,198		44,444
Other long-term liabilities	166,358		55,627
Total liabilities	10,777,838		8,723,376

Commitments and contingencies (Note 23)

Series B convertible preferred stock, $0.01 par value, 96,746 shares authorized, issued and outstanding as of December 31, 2024 (0 as of December 31, 2023); aggregate liquidation preference of $96,746 and $0 at December 31, 2024 and December 31, 2023	90,570		—

Stockholders’ equity
Class A common stock, $0.01 par value, 750.0 million shares authorized, 266.5 million issued and outstanding as of December 31, 2024; 205.0 million issued and outstanding as of December 31, 2023	2,664		2,050
Additional paid-in capital	1,674,312		1,038,530
Retained earnings	196,363		527,986
Accumulated other comprehensive income	3,089		71,528
Total stockholders’ equity attributable to NFE	1,876,428		1,640,094
Non-controlling interest	122,660		137,775
Total stockholders’ equity	1,999,088		1,777,869
Total liabilities and stockholders’ equity	$	12,867,496	$	10,501,245

The accompanying notes are an integral part of these consolidated financial statements.

F-6

Table of Contents

New Fortress Energy Inc.

Consolidated Statements of Operations and Comprehensive (Loss) Income

For the years ended December 31, 2024, 2023 and 2022

(in thousands of U.S. dollars, except share and per share amounts)


	Year Ended December 31,
	2024		2023		2022
Revenues
Operating revenue	$	1,698,348	$	2,060,212	$	1,978,645
Vessel charter revenue	212,609		276,843		357,158
Contract novation income	295,558		—		—
Other revenue	158,345		76,241		32,469
Total revenues	2,364,860		2,413,296		2,368,272

Operating expenses
Cost of sales (exclusive of depreciation and amortization shown separately below)	1,064,667		877,451		1,010,428
Vessel operating expenses	33,372		45,439		63,518
Operations and maintenance	174,313		166,785		105,800
Selling, general and administrative	285,520		205,104		236,051
Transaction and integration costs	12,279		6,946		21,796
Depreciation and amortization	162,014		187,324		142,640
Asset impairment expense	16,494		10,958		50,659
Loss (gain) on sale of assets, net	77,562		(29,378)		—
Total operating expenses	1,826,221		1,470,629		1,630,892
Operating income	538,639		942,667		737,380
Interest expense	328,377		277,842		236,861
Other expense (income), net	113,077		10,408		(48,044)
Loss on extinguishment of debt, net	270,063		—		14,997
(Loss) income before income from equity method investments and income taxes	(172,878)		654,417		533,566
Income (loss) from equity method investments	—		9,972		(472,219)
Tax provision (benefit)	69,509		115,513		(123,439)
Net (loss) income	(242,387)		548,876		184,786


Net (loss) income attributable to common stockholders	$	(270,106)	$	547,882	$	194,479

Net (loss) income per share – basic	$	(1.24)	$	2.66	$	0.93
Net (loss) income per share – diluted	$	(1.25)	$	2.65	$	0.93

Weighted average number of shares outstanding – basic	217,578,487		205,942,837		209,501,298
Weighted average number of shares outstanding – diluted	218,622,419		206,481,977		209,854,413

Other comprehensive (loss) income:
Currency translation adjustment	(69,468)		18,005		68,403
Reclassification of net foreign currency translation adjustment realized upon sale of foreign subsidiary	—		(1,457)		—
Comprehensive (loss) income	(311,855)		565,424		253,189
Comprehensive (income) loss attributable to non-controlling interest	(5,623)		(1,412)		10,795
Comprehensive (loss) income attributable to stockholders	$	(317,478)	$	564,012	$	263,984

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

New Fortress Energy Inc.

Consolidated Statements of Changes in Stockholders’ Equity

For the years ended December 31, 2024, 2023 and 2022

(in thousands of U.S. dollars, except share amounts)


	Series B convertible preferred stock			Class A common stock			Additional paid-in capital		Retained earnings (Accumulated deficit)		Accumulated other comprehensive (loss) income		Non-controlling Interest		Total stockholders’ equity
	Shares	Amount		Shares	Amount
Balance as of January 1, 2022	—	$	—	206,863,242	$	2,069	$	1,923,990	$	(132,399)	$	(2,085)	$	202,479	$	1,994,054
Net income (loss)	—	—		—	—		—		194,479		—		(9,693)		184,786
Other comprehensive income	—	—		—	—		—		—		69,505		(1,102)		68,403
Currency translation adjustment released upon Sergipe Sale	—	—		—	—		—		—		(12,022)		—		(12,022)
Share-based compensation expense	—	—		—	—		30,382		—		—		—		30,382
Issuance of shares for vested RSU/PSUs	—	—		3,426,213	19		(12)		—		—		—		7
Shares withheld from employees related to share-based compensation, at cost	—	—		(1,519,367)	—		(74,822)		—		—		—		(74,822)
Deconsolidation of Nanook, Celsius and Penguin SPVs	—	—		—	—		—		—		—		(23,569)		(23,569)
Dividends	—	—		—	—		(709,284)		—		—		(16,076)		(725,360)
Balance as of December 31, 2022	—	$	—	208,770,088	$	2,088	$	1,170,254	$	62,080	$	55,398	$	152,039	$	1,441,859
Net income	—	—		—	—		—		547,882		—		994		548,876
Other comprehensive income	—	—		—	—		—		—		16,130		418		16,548
Share-based compensation expense	—	—		—	—		1,573		—		—		—		1,573
Acquisition and cancellation of shares	—	—		(4,100,000)	(41)		(123,778)		—		—		—		(123,819)
Issuance of shares for vested share-based compensation awards	—	—		689,401	3		—		—		—		—		3
Shares withheld from employees related to share-based compensation, at cost	—	—		(328,083)	—		(9,519)		—		—		—		(9,519)
Dividends	—	—		—	—		—		(81,976)		—		(15,676)		(97,652)
Balance as of December 31, 2023	—	$	—	205,031,406	$	2,050	$	1,038,530	$	527,986	$	71,528	$	137,775	$	1,777,869
Net income (loss)	—	—		—	—		—		(249,039)		—		6,652		(242,387)
Other comprehensive income (loss)	—	—		—	—		—		—		(68,439)		(1,029)		(69,468)
Share-based compensation expense	—	—		—	—		50,625		—		—		—		50,625
Class A stock issued, net of issuance costs	—	—		61,389,733	614		562,201		—		—		—		562,815
Issuance of shares for vested share-based compensation awards	—	—		54,035	—		—		—		—		—		—
Shares withheld from employees related to share-based compensation, at cost	—	—		(16,081)	—		(435)		—		—		—		(435)
Issuance of preferred stock and deemed dividend (Note 4)	96,746	107,189		—	—		6,772		(17,605)		—		—		(10,833)
Conversion of Series B convertible preferred stock	—	(16,619)		—	—		16,619		—		—		—		16,619
Dividends	—	—		—	—		—		(64,979)		—		(20,738)		(85,717)
Balance as of December 31, 2024	96,746	$	90,570	266,459,093	$	2,664	$	1,674,312	$	196,363	$	3,089	$	122,660	$	1,999,088

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

New Fortress Energy Inc.

Consolidated Statements of Cash Flows

For the years ended December 31, 2024, 2023 and 2022

(in thousands of U.S. dollars)


	Year Ended December 31,
	2024		2023		2022
Cash flows from operating activities
Net (loss) income	$	(242,387)	$	548,876	$	184,786
Adjustments for:
Amortization of deferred financing costs and debt guarantee, net	33,173		6,589		2,536
Depreciation and amortization	162,525		187,324		143,589
(Earnings) losses of equity method investees	—		(9,972)		472,219



Current expected credit losses	13,959		203		869


Deferred taxes	5,466		14,938		(279,536)

Share-based compensation	50,625		1,573		30,382

Earnings recognized from vessels chartered to third parties transferred to Energos	(95,487)		(156,997)		(49,686)
Loss on the disposal of equity method investment	7,222		37,401		—
Loss (gain) on sale of assets, net	77,562		(29,378)		—
Loss on extinguishment of debt	270,063		—		14,997

Other	153,338		34,819		(60,243)
Changes in operating assets and liabilities, net of acquisitions:
Decrease (increase) in receivables	64,726		(41,019)		(139,938)
(Increase) in inventories	(2,751)		(39,790)		(7,933)
(Increase) decrease in other assets	(65,445)		41,828		(30,086)
Decrease in right-of-use assets	164,136		83,537		63,593
Increase in accounts payable/accrued liabilities	187,792		78,065		67,741

(Decrease) in lease liabilities	(160,604)		(74,576)		(63,493)
(Decrease) increase in other liabilities	(37,171)		141,335		5,314
Net cash provided by operating activities	586,742		824,756		355,111

Cash flows from investing activities
Capital expenditures	(2,621,234)		(3,029,834)		(1,174,008)


Proceeds from sale of net investment in lease	—		—		593,000
Sale of equity method investment	136,365		100,000		500,076
Asset sales	328,999		16,464		—
Sale of Miami Facility	58,336		—		—
Other investing activities	22,887		9,227		(1,794)
Net cash used in investing activities	(2,074,647)		(2,904,143)		(82,726)

Cash flows from financing activities
Proceeds from borrowings of debt	5,865,299		3,005,387		2,032,020

Payment of deferred financing costs	(146,722)		(37,806)		(17,598)
Repayment of debt	(3,801,034)		(686,508)		(1,520,813)
Issuance of Class A stock	386,583		—		—
Payment of dividends	(65,310)		(723,962)		(99,050)
Other financing activities	(14,248)		(28,161)		(72,602)
Net cash provided by financing activities	2,224,568		1,528,950		321,957

Impact of changes in foreign exchange rates on cash and cash equivalents	(81,900)		6,168		(3,289)
Net increase (decrease) in cash, cash equivalents and restricted cash	654,763		(544,269)		591,053
Cash, cash equivalents and restricted cash – beginning of period	310,814		855,083		264,030
Cash, cash equivalents and restricted cash – end of period	$	965,577	$	310,814	$	855,083

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

New Fortress Energy Inc.

Consolidated Statements of Cash Flows

For the years ended December 31, 2024, 2023 and 2022

(in thousands of U.S. dollars)


	Year Ended December 31,
	2024		2023		2022
Cash paid for interest, net of capitalized interest	$	105,784	$	100,304	$	160,618
Cash paid for taxes	27,932		52,897		151,210

	Year Ended December 31,
	2024		2023		2022
Supplemental disclosure of non-cash investing and financing activities:
Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions	$	(267,366)	$	322,598	$	284,390
Accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions	463,657		738,163		422,391


Consideration received on asset sale	—		27,704		—
Principal payments on financing obligation paid to Energos by third party charters	(21,731)		(66,866)		(24,949)
Shares received in Hilli Exchange	—		(122,754)		—
Investment in Energos	—		1,501		129,518
Accrued dividend	20,507		—		626,310
Preferred shares issued and debt assumed in PortoCem acquisition	(125,198)		—		—
Fair value of contingent payments in the Lins acquisition	8,080		—		—
Deemed dividend related to Series B preferred stock	(17,605)		—		—
Non-cash financing costs	181,928		—		46,371

The following table identifies the balance sheet line-items included in Cash and cash equivalents, Current restricted cash, and Non-current restricted cash presented in Other non-current assets, net on the Consolidated Balance Sheets (Note 17) presented in the Consolidated Statement of Cash Flows:


	Year Ended December 31,
	2024		2023
Cash and cash equivalents	492,881		155,414
Current restricted cash	472,696		155,400


Cash, cash equivalents and restricted cash – end of period	$	965,577	$	310,814

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

1. Organization

New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”), a Delaware corporation, is a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. The Company owns and operates natural gas and liquefied natural gas ("LNG") infrastructure, ships and logistics assets to rapidly deliver turnkey energy solutions to global markets. The Company has liquefaction, regasification and power generation operations in the United States, Jamaica, Brazil and Mexico. The Company has marine operations with vessels operating under time charters and in the spot market globally.

The Company currently conducts its business through two operating segments, Terminals and Infrastructure and Ships. The business and reportable segment information reflect how the Chief Operating Decision Maker (“CODM”) regularly reviews and manages the business. The Company's CODM is its Chief Executive Officer.

2. Significant accounting policies

The principal accounting policies adopted are set out below.

(a)Basis of presentation and principles of consolidation

The accompanying consolidated financial statements contained herein were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned consolidated subsidiaries. The ownership interest of other investors in consolidated subsidiaries is recorded as a non-controlling interest. All significant intercompany transactions and balances have been eliminated on consolidation. Certain prior year amounts have been reclassified to conform to current year presentation.

Non-controlling interests are classified as a separate component of equity on the Consolidated Balance Sheets and Consolidated Statements of Changes in Stockholders’ Equity. Additionally, net income and comprehensive income (loss) attributable to non-controlling interests are reflected separately from consolidated net income and comprehensive income in the Consolidated Statements of Operations and Comprehensive (Loss) Income and Consolidated Statements of Changes in Stockholders’ Equity. Any change in ownership of a subsidiary while the controlling financial interest is retained is accounted for as an equity transaction between the controlling and non-controlling interests. Losses continue to be attributed to the non-controlling interests, even when the non-controlling interests’ basis has been reduced to zero.

The accompanying financial statements have been prepared on the basis that the Company will continue as a going concern over the next twelve months from the date of issuance of these financial statements, which assumes the realization of assets and the satisfaction of liabilities in the normal course of business. Under ASC 205-40, when first assessing whether substantial doubt is raised about the entity’s ability to continue as a going concern, management cannot consider the potential mitigating effects of its plans that have not been fully implemented at the assessment date. Management has concluded that the Company’s current liquidity and forecasted cash flows (which exclude the effect of the Transactions as defined below), from operations are not sufficient to support, in full, obligations as they become due. Management has approved a plan to support its liquidity position by: (i) delaying certain discretionary payments, including planned capital expenditures and dividends, that are within management’s control, and (ii) continuously renewing the LNG cargo financing facility over the succeeding twelve months. Management’s plan also includes the availability of a backstop agreement that was executed in March 2025 (Note 30) and provides up to $100,000 of availability. Management concluded that such plans are probable of being implemented and the Company will have sufficient liquidity to meet its obligations as they become due over the next twelve months from the date that the consolidated financial statements were issued. In addition to management’s plan outlined above, the Company continues to explore asset sales, settlement of claims and other strategic transactions (collectively, the “Transactions”) that seek to optimize the value of the Company’s portfolio while providing additional liquidity and cash flow to the Company. However, there are inherent uncertainties, as the execution of the Transactions are outside of management’s control and therefore there are no assurances that these transactions will be executed. Furthermore, there are inherent risks with the Company’s ability to continue to implement plans in future periods that will support its liquidity position, such as its ability to further extend the terms of vendor payments and other obligations.

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Table of Contents

(b)Use of estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Management evaluates its estimates and related assumptions regularly. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

(c)Foreign currencies

The Company has certain foreign subsidiaries in which the functional currency is the local currency. All of the assets and liabilities of these subsidiaries are translated to U.S. dollars at the exchange rate in effect at the balance sheet date; income and expense accounts are translated at average rates for the period. The effects of translating financial statements of foreign operations into our reporting currency are recognized as a cumulative translation adjustment in accumulated other comprehensive income.

The Company also has foreign subsidiaries that conduct business in currencies other than their respective functional currencies. Transactions are remeasured to the subsidiaries’ functional currency at the exchange rate in effect on the dates of such transactions. Net realized foreign currency gains or losses relating to the differences between these recorded amounts and the functional currency equivalent actually received or paid are included within Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in Accumulated other comprehensive income. Accumulated foreign currency translation adjustments are reclassified from Accumulated other comprehensive income to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. If the Company commits to a plan to sell or liquidate a foreign entity, accumulated foreign currency translation adjustments would be included in carrying amounts in impairment assessments.

(d)Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

(e)Restricted cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on the Consolidated Balance Sheets.

(f)Receivables

Receivables are contractual rights to receive cash on a fixed or determinable date and are recognized on the balance sheet as the amount invoiced to the customer, net of an allowance for current expected credit losses. Accounts receivable are carried at amortized cost. Amounts are written off against the allowance when management is certain that outstanding amounts will not be collected. The Company estimates expected credit losses based on relevant information about the current credit quality of customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectability of the reported amount. Credit loss expense, inclusive of credit loss expense on all categories of financial assets, is recorded within Selling, general and administrative in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(g)Inventories

LNG and natural gas inventories, bunker fuel inventories and automotive diesel oil inventories are recorded at weighted average cost, and materials and other inventory are recorded at cost. The Company’s cost to convert natural gas to LNG, which primarily consists of labor, depreciation and other direct costs to operate liquefaction facilities, is reflected in Inventory on the Consolidated Balance Sheets.

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Table of Contents

LNG is subject to “boil-off,” a natural loss of gas volume over time when LNG is exposed to environments with temperatures above its optimum storage state. Boil-off losses are expensed through Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income in instances where gas cannot be contained and recycled back into the production process.

(h)Construction in progress

Construction in progress is recorded at cost, and at the point at which the constructed asset is put into use, the full cost of the asset is reclassified from Construction in progress to Property, plant and equipment, net or Finance leases, net on the Consolidated Balance Sheets. Construction progress payments, engineering costs, certain direct payroll costs and other costs directly relating to the asset under construction are capitalized during the construction period, provided the completion of the construction project is deemed probable or if the costs are associated with activities that could be utilized in future projects. Prior to putting projects into service the Company may utilize gas to test and commission the assets, and the Company may be able to invoice our customers for gas used in commissioning. Amounts received as a result of the sale of test gas reduce the Construction in progress balance. Depreciation is not recognized during the construction period and commences when the assets are ready for their intended use, which may require management to make subjective judgments and assumptions about the conditions necessary for the assets to be capable of operating in the intended manner.

The interest cost associated with major development and construction projects is capitalized during the construction period and included in the cost of the project in Construction in progress.

(i)Property, plant and equipment, net

Property, plant and equipment is initially recorded at cost. Expenditures for construction activities and betterments that extend the useful life of the asset are capitalized. Vessel refurbishment costs are capitalized and depreciated over the vessels’ remaining useful economic lives. Refurbishment costs increase the capacity or improve the efficiency or safety of vessels and equipment. Expenditures for routine maintenance and repairs for assets in the Terminals and Infrastructure segment are charged to expense as incurred within Operations and maintenance in the Consolidated Statements of Operations and Comprehensive (Loss) Income; such expenditures for assets in the Ships segment that do not improve the operating efficiency or extend the useful lives of the vessels are expensed as incurred within Vessel operating expenses.

Major maintenance and overhauls of the Company’s power plant and terminals are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul.

Drydocking expenditures, including drydocking expenditures related to vessels that were included in the Energos Formation Transaction (defined below), are capitalized when incurred and amortized over the period until the next anticipated drydocking, which is generally five years. For vessels, the Company utilizes the “built-in overhaul” method of accounting and segregates vessel costs into those that should be depreciated over the useful life of the vessel and those that require drydocking at periodic intervals. If drydocking occurs prior to the expected timing, a cumulative adjustment to recognize the change in expected timing of drydocking is recognized within Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

The Company depreciates property, plant and equipment less the estimate residual value using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives:


			Useful life (Yrs)
Vessels			5-30
Terminal and power plant equipment			4-24
Power facilities			4-20
ISO containers and other equipment			3-25
LNG liquefaction facilities			20-40
Gas pipelines			4-24
Leasehold improvements			2-20

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Table of Contents

The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted.

Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in Loss (gain) on sale of assets, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. When a vessel is disposed, any unamortized drydocking expenditure is recognized as part of the gain or loss on disposal in the period of disposal.

(j)Impairment of long-lived assets

The Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for LNG to the Company’s operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract or the introduction of newer technology.

Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.

(k)Investments in equity securities

Investments in equity securities are carried at fair value and included in Other non-current assets on the Consolidated Balance Sheets, with gains or losses recorded in earnings in Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(l)Cloud computing costs

The Company capitalizes the costs incurred during the implementation stage for cloud computing or hosting arrangements. Costs incurred in the preliminary project stage and post-implementation stage, which includes maintenance and training costs, are expensed as incurred. Such costs are recorded in Transaction and integration costs in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Capitalized software costs are amortized over the straight-line method over three to five years and are recorded in Other assets on the Consolidated Balance Sheets. Amortization expense is recorded in Selling, general and administrative in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(m)Intangible assets

Upon a business combination or asset acquisition, the Company may obtain identifiable intangible assets. Intangible assets with a finite life are amortized over the estimated useful life of the asset under the straight-line method.

Indefinite lived intangible assets are not amortized. Intangible assets with an indefinite useful life are tested for impairment on an annual basis, on October 1st of each year, or more frequently if changes in circumstances indicate that it is more likely than not that the asset is impaired. Indefinite lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(n)Goodwill

Goodwill includes the excess of the purchase price over the fair value of the net tangible and intangible assets acquired in a business combination.

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Table of Contents

The Company reviews the carrying values of goodwill at least annually to assess impairment since these assets are not amortized. An annual impairment assessment is conducted as of October 1st of each year. Additionally, the Company reviews the carrying value of goodwill whenever events or changes in circumstances indicate that its carrying amount may not be recoverable.

For an annual goodwill impairment assessment, an optional qualitative analysis may be performed. If the option is not elected or if it is more likely than not that the fair value of a reporting unit is less than its carrying amount, then a two-step goodwill impairment test is performed to identify potential goodwill impairment and to measure an impairment loss.

A goodwill impairment assessment compares the fair value of a respective reporting unit with its carrying amount, including goodwill. The estimate of fair value of the respective reporting unit is based on the best information available as of the date of assessment, which primarily incorporates assumptions about operating results, business plans, income projections, anticipated future cash flows and market data. If goodwill is determined to be impaired, an impairment loss, measured at the amount by which the reporting unit’s carrying amount exceeds its fair value, not to exceed the carrying amount of goodwill, is recorded.

There was no impairment of goodwill for the years ended December 31, 2024 and 2023.

(o)Long-term debt and debt issuance costs

We evaluate the terms of our debt arrangements to determine whether they contain an embedded derivative that is required to be bifurcated. Any embedded derivatives that are required to be bifurcated are recorded at fair value on the Consolidated Balance Sheets.

Costs directly related to the issuance of debt are reported on the Consolidated Balance Sheets as a reduction from the carrying amount of the recognized debt liability and amortized over the term of the debt using the effective interest method. Unamortized debt issuance costs associated with the revolving credit agreement, facilities for the issuance of letters of credit and other similar arrangements are presented as an asset within Other non-current assets on the Consolidated Balance Sheets (regardless of whether there are any amounts outstanding under the credit facility) and amortized over the life of the particular arrangement. Interest and related amortization of debt issuance costs recognized during major development and construction projects are capitalized and included in the cost of the project.

The Company evaluates changes to debt arrangements to determine whether the changes represent a modification or extinguishment to the old debt arrangement. If a debt instrument is deemed to be modified, all new lender fees are capitalized, and third-party fees associated with the previous lenders are recognized as expense within Transaction and integration costs in the Consolidated Statements of Operations and Comprehensive (Loss) Income. If an extinguishment of debt instruments has occurred, the unamortized financing fees associated with the extinguished instrument and lender fees are expensed to Loss on extinguishment of debt, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. In the event an amendment to the Revolving Facility (defined below) reduces the committed capacity of any lenders, the portion of any unamortized fees associated with such lender is expensed on a pro-rata basis in proportion to the decrease in the committed capacity.

(p)Contingencies

The Company may be involved in legal actions in the ordinary course of business, including governmental and administrative investigations, inquiries and proceedings concerning employment, labor, environmental and other claims. The Company recognizes a loss contingency in the consolidated financial statements when it is probable a liability has been incurred and the amount of the loss can be reasonably estimated. The Company discloses any loss contingencies that do not meet both conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.

(q)Revenue recognition

Terminals and Infrastructure

Within the Terminals and Infrastructure segment, the Company’s contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from the Company’s natural gas-fueled infrastructure and the sale of LNG cargos. The transaction price for each of these contracts is

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structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is delivered in containers transported by truck to customer sites but may also be delivered via vessel to an unloading point specified in a contract. Revenue from sales of LNG is recognized at the point in time at which of the LNG transfers to the customer, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, the Company has presented Operating revenue on an aggregated basis.

The Company has concluded that the variable consideration included in its agreements meets the exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer.

The Company’s contracts with industrial end-user customers to supply natural gas or LNG may contain a lease of equipment or vessels, which may be accounted for as a finance or operating lease. For operating leases, the Company has elected the practical expedient to combine revenue for the sale of natural gas or LNG and operating lease income as the timing and pattern of transfer of the components are the same. The Company has concluded that the predominant component of the transaction is the sale of natural gas or LNG and therefore has not separated the lease component. The lease component of such operating leases is recognized as Operating revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The Company allocates consideration in agreements containing finance leases between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. The Company estimates the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term.

The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Other non-current assets, net on the Consolidated Balance Sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The principal component of the lease payment is reflected as a reduction to the net investment in the lease.

Other revenue includes revenue recognized by the Company's subsidiary, Genera PR LLC ("Genera"), under its contract for the operation and maintenance of Puerto Rico Electric Power Authority's ("PREPA") thermal generation assets. Under this agreement, Genera is reimbursed for pass-through expenses, including payroll expenses of Genera employees. Genera is the principal for operation and maintenance services, and the Company recognizes revenue for amounts to be reimbursed by PREPA in the period such expenses are incurred. Genera is also eligible for performance-based incentive fees, which are considered variable consideration. The Company estimates the amount of variable consideration as the most likely amount, which is included in the transaction price to the extent that it is probable that a significant reversal of cumulative revenue recognized will not occur.

In addition, the Company's agreements may include a significant financing component, and the Company recognizes revenue for the interest income component over the term of the financing as Other revenue.

The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration. Contract assets include unbilled amounts resulting from contracts with variable considerations, in which the performance obligation is satisfied and revenue is recognized. Contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the Consolidated Balance Sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities and Other long-term liabilities on the Consolidated Balance Sheets.

Shipping and handling costs are not considered to be separate performance obligations. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas.

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The Company collects sales taxes from its customers based on sales of taxable products and remits such collections to the appropriate taxing authority. The Company has elected to present sales tax collections in the Consolidated Statements of Operations and Comprehensive (Loss) Income on a net basis and, accordingly, such taxes are excluded from reported revenues.

The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less.

Ships

Charter contracts, that have a lease term greater than one year, for the use of the FSRUs and LNG carriers are leases as the contracts convey the right to obtain substantially all of the economic benefits from the use of the asset and allow the customer to direct the use of that asset.

At inception, the Company makes an assessment on whether the charter contract is an operating lease or a finance lease. Renewal periods and termination options are included in the lease term if the Company believes such options are reasonably certain to be exercised by the lessee. Generally, lease accounting commences when the asset is made available to the customer, however, where the contract contains specific customer acceptance testing conditions, the lease will not commence until the asset has successfully passed the acceptance test. The Company assesses leases for modifications when there is a change to the terms and conditions of the contract that results in a change in the scope or the consideration of the lease.

For charter contracts that are determined to be finance leases accounted for as sales-type leases, the profit from the sale of the vessel is recognized upon lease commencement in Other revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. Revenue related to operating and service agreements in connection with charter contracts accounted for as sales-type leases are recognized over the term of the charter as the service is provided within Vessel charter revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

Revenue includes lease payments under charters accounted for as operating leases and fees for repositioning vessels. Revenue generated from charters contracts is recorded over the term of the charter on a straight-line basis as service is provided and is included in Vessel charter revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Lease payments include fixed payments (including in-substance fixed payments that are unavoidable) and variable payments based on a rate or index. For operating leases, the Company has elected the practical expedient to combine service revenue and operating lease income as the timing and pattern of transfer of the components are the same. Variable lease payments are recognized in the period in which the circumstances on which the variable lease payments are based become probable or occur.

Repositioning fees are included in Vessel charter revenue and are recognized at the end of the charter when the fee becomes fixed. However, where there is a fixed amount specified in the charter, which is not dependent upon redelivery location, the fee is recognized evenly over the term of the charter.

Costs directly associated with the execution of the lease or costs incurred after lease inception but prior to the commencement of the lease that directly relate to preparing the asset for the contract are capitalized and amortized in Vessel operating expenses in the Consolidated Statements of Operations and Comprehensive (Loss) Income over the lease term.

The Company continues to be the accounting owner of vessels included in the Energos Formation Transaction (Note 13), and the Company accounts for third party charters of these vessels under the accounting policies for vessel leases described above. The third-party charters of these vessels are operating leases, and revenue is recognized from these charters within Vessel charter revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

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(r)Leases, as lessee

The Company has entered into lease agreements primarily for the use of LNG vessels, marine port space, office space, land and equipment. Right-of-use (“ROU”) assets recognized for these leases represent the Company’s right to use an underlying asset for the lease term, and the lease liabilities represent the Company’s obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the estimated present value of fixed lease payments over the lease term.

Leases with terms of 12 months or less are excluded from ROU assets and lease liabilities on the balance sheet, and short-term lease payments are recognized on a straight-line basis over the lease term. Variable payments under short-term leases are recognized in the period in which the obligation that triggers the variable payment becomes probable.

The Company, as lessee, has also elected the practical expedient not to separate lease and non-lease components for marine port space, office space, land and equipment leases. The Company separates the lease and non-lease components for vessel leases. The allocation of lease payments between lease and non-lease components has been determined based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone price to lease a bareboat vessel. The fair value of the non-lease component is estimated based on the estimated standalone price of operating the respective vessel, inclusive of the costs of the crew and other operating costs.

The Company has elected the land easement practical expedient, which allows the Company to continue to account for pre-existing land easements as intangible assets under the accounting policy that existed before adoption of ASC 842 Leases.

(s)Share-based compensation

The Company adopted the New Fortress Energy Inc. 2019 Omnibus Incentive Plan (the “Incentive Plan”), effective as of February 4, 2019. Under the Incentive Plan, the Company may issue options, share appreciation rights, restricted shares, restricted share units (“RSUs”), performance share units (“PSUs”) or other share-based awards to selected officers, employees, non-employee directors and select non-employees of NFE or its affiliates. The Company accounts for share-based compensation in accordance with ASC 718, Compensation and ASC 505, Equity, which require all share-based payments to employees and members of the board of directors to be recognized as expense in the consolidated financial statements based on their grant date fair values. The fair value is adjusted for material non-public information that the Company may be aware of as of the grant date. The Company has elected not to estimate forfeitures of its share-based compensation awards but recognizes the reversal in compensation expense in the period in which the forfeiture occurs.

The Company has granted PSUs to certain employees and non-employees. The PSUs contain a performance condition, and vesting is determined based on achievement of a performance metric in the year subsequent to the grant. Compensation expense is recognized on a straight-line basis over the service period based on the expected attainment of a performance metric. At each reporting period, the Company reassesses the probability of the achievement of the performance metric, and any increase or decrease in share-based compensation expense resulting from an adjustment in the number of shares expected to vest is treated as a cumulative catch-up in the period of adjustment.

(t)Lessor expense recognition

Vessel operating expenses are recognized when incurred. Vessel operating expenses include crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses and third-party management fees. Initial direct costs include costs directly related to the negotiation and consummation of the lease and are deferred and recognized in Vessel operating expenses over the lease term.

Certain vessels included in the Energos Formation Transaction (defined below) are chartered to third parties under operating leases. As the accounting owner of these vessels, the Company recognizes the cost of operating these vessels in Vessel operating expenses.

(u)Transaction and integration costs

Transaction and integration costs is comprised of costs related to business combinations and dispositions and include advisory, legal, accounting, valuation and other professional or consulting fees. This caption also includes gains or losses recognized in connection with business combinations, including the settlement of preexisting relationships between the Company and an acquired entity. Financing costs which are not deferred as part of the cost of the financing on the balance

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sheet including fees associated with debt modifications are recognized within this caption. The Company records cloud computing costs incurred in the preliminary project stage and post-implementation stage within this caption.

(v)Taxation

The Company accounts for income taxes in accordance with ASC 740, Accounting for Income Taxes (“ASC 740”), under which deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts and the tax bases of assets and liabilities by applying the enacted tax rates in effect for the year in which the differences are expected to reverse. Such net tax effects on temporary differences are reflected on the Company’s Consolidated Balance Sheets as deferred tax assets and liabilities. Deferred tax assets are reduced by a valuation allowance when the Company believes that it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

The Company recognizes the effect of tax positions only if those positions are more likely than not of being sustained. Recognized tax positions are measured at the largest amount that is greater than 50 percent likely of being realized upon ultimate settlement with the relevant tax authority. Conclusions reached regarding tax positions are continually reviewed based on ongoing analyses of tax laws, regulations and interpretations thereof. To the extent that the Company’s assessment of the conclusions reached regarding tax positions changes as a result of the evaluation of new information, such change in estimate will be recorded in the period in which such determination is made. The Company reports interest and penalties relating to an underpayment of income taxes, if applicable, as a component of income tax expense.

The Company has elected to treat amounts incurred under the global intangible low-taxed income (“GILTI”) rules as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.

Other taxes

Certain subsidiaries may be subject to payroll taxes, excise taxes, property taxes, sales and use taxes, in addition to income taxes in foreign countries in which they conduct business. In addition, certain subsidiaries are exposed to local state taxes, such as franchise taxes. Local state taxes that are not income taxes are recorded within Selling, general and administrative in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(w)Net income per share

Basic net income per share (“EPS”) is computed by dividing net income attributable to Class A common stock by the weighted average number of shares of Class A common stock outstanding. The dilutive effect of outstanding awards, if any, is reflected in diluted earnings per share by application of the treasury stock method or if-converted method, as applicable.

(x)Acquisitions

Business combinations are accounted for under the acquisition method. On acquisition, the identifiable assets acquired and liabilities assumed are measured at their fair values at the date of acquisition. Any excess of the purchase price over the fair values of the identifiable net assets acquired is recognized as goodwill. Acquisition-related costs are expensed as incurred as Transaction and integration costs in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The results of operations of acquired businesses are included in the Company’s Consolidated Statements of Operations and Comprehensive (Loss) Income from the date of acquisition.

If the assets acquired do not meet the definition of a business, the transaction is accounted for as an asset acquisition and no goodwill is recognized. Costs incurred in conjunction with asset acquisitions are included in the purchase price, and any excess consideration transferred over the fair value of the net assets acquired is reallocated to the identifiable assets based on their relative fair values.

(y)Equity method investments

The Company accounts for investments in entities over which the Company has significant influence, but do not meet the criteria for consolidation, under the equity method of accounting. Under the equity method of accounting, the Company’s investment is recorded at cost. In the case of equity method investments acquired as part of a business combination or

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acquired in exchange for the contribution of assets or entities to the investee, the investment is initially recorded at the acquisition date fair value of the investment. The carrying amount is adjusted for the Company’s share of the earnings or losses, and dividends received from the investee reduce the carrying amount of the investment. The Company allocates the difference between the fair value of investments acquired in a business combination and the Company’s proportionate share of the carrying value of the underlying assets, or basis difference, across the assets and liabilities of the investee. The basis difference assigned to amortizable net assets is included in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive (Loss) Income. When the Company’s share of losses in an investee equals or exceeds the carrying value of the investment, no further losses are recognized unless the Company has incurred obligations or made payments on behalf of the investee.

The Company periodically assesses if impairment indicators exist at equity method investments. When an impairment is observed, any excess of the carrying amount over its estimated fair value is recognized as impairment expense when the loss in value is deemed other-than-temporary and included in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

In relation to the Company's 20% equity interest in Energos, the Company elected to recognize its proportional share of the income or loss from the equity method investment on a financial reporting lag of one fiscal quarter. The Company did not elect to recognize the results of other equity method investments on a financial reporting lag.

(z)Loss of control of subsidiary

When there is a loss of control over a subsidiary, the Company de-consolidates the entity as of the date the Company ceases to have a controlling financial interest. The Company accounts for the deconsolidation of a subsidiary by recognizing a gain or loss in the Consolidated Statements of Operations and Comprehensive (Loss) Income, measured by the difference between the aggregate of the fair value of the consideration received, fair value of any retained non-controlling interest in the former subsidiary and the carrying amount of any non-controlling interest in the former subsidiary with the carrying amount of the former subsidiary’s assets and liabilities. If a change of ownership interest causes a loss of control of a foreign entity, in addition to de-recognizing the assets and liabilities, the Company will also de-recognize any amounts previously recorded in other comprehensive income.

(aa)Guarantees

Guarantees issued by the Company, excluding those that are guaranteeing the Company’s own performance, are recognized at fair value at the time that the guarantees are issued and recognized in Other non-current liabilities on the Consolidated Balance Sheets. Guarantee liabilities are amortized using a systematic and rational method as the risk to the Company is reduced. If it becomes probable that the Company will have to perform under a guarantee, the Company will recognize an additional liability if the amount of the loss can be reasonably estimated.

(ab)Derivatives

The Company has entered into derivative positions that were used to reduce market risks associated with interest rates, foreign exchange rates and commodity prices. The Company also accounts for arrangements that require the Company to pay sellers contingent payments in asset acquisitions as derivatives. All derivative instruments are initially recorded at fair value as either assets or liabilities on the Consolidated Balance Sheets and subsequently remeasured to fair value, regardless of the purpose or intent for holding the derivative, unless they qualify for a Normal Purchases and Normal Sales (“NPNS”) exception. The Company has not designated any derivatives as cash flow or fair value hedges; however, certain instruments may be considered economic hedges. Cash inflows and outflows related to commodity derivatives, foreign currency and interest rate swap are classified in the Consolidated Statements of Cash Flows based on the risk that the instrument is intended to mitigate, which may be operating, investing or financing.

Revenues and expenses on contracts that qualify for the NPNS exception are recognized when the underlying physical transaction is delivered under other applicable GAAP (e.g., ASC 606 or ASC 705). While these contracts are considered derivative financial instruments under ASC 815, Derivatives and Hedging, they are not recorded at fair value, but on an accrual basis of accounting. If it is determined that a transaction designated as NPNS no longer meets the scope exception, the fair value of the related contract is recorded on the balance sheet and immediately recognized through earnings.

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3. Adoption of new and revised standards

New standards, amendments and interpretations issued but not effective for the year beginning January 1, 2024:

In December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, requiring companies to annually disclose specific categories in the effective tax rate reconciliation and provide additional information for reconciling items that meet a quantitative threshold. Further, the ASU requires disclosure of income taxes paid (net of refunds received) disaggregated by federal (national), state and foreign taxes and to disaggregate the information by jurisdiction based on a quantitative threshold. The amendments in this ASU are effective for annual periods beginning after December 15, 2024, and early adoption is permitted. The amendments should be applied on a prospective basis, but retrospective application is permitted. The Company is currently reviewing the impact that the adoption of ASU 2023-09 may have on the Company's financial statements and disclosures.

In March 2024, the FASB issued ASU 2024-01, Compensation—Stock Compensation (Topic 718): Scope Application of Profits Interest and Similar Awards, providing illustrative guidance to help entities determine whether profits interest and similar awards should be accounted for as share-based payment arrangements within the scope of Topic 718. The amendments in this ASU are effective for annual periods beginning after December 15, 2024, and interim periods within those annual periods. Early adoption is allowed, and the amendments can be applied on a prospective or retrospective basis. The Company will adopt ASU 2024-01 on January 1, 2025 and apply the amendments on a prospective basis.

In November 2024, the FASB issued ASU 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. These amendments require public business entities to disclose additional information about specific expense categories in the notes to financial statements at each interim and annual reporting period. ASU 2024-03 will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The amendments can be applied prospectively or retrospectively. The Company is currently reviewing the impact that the adoption of ASU 2024-03 may have on the Company's financial statements and disclosures.

New and amended standards adopted by the Company:

In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. ASU 2023-07 requires disclosure of significant segment expenses and other segment items that are regularly provided to the CODM and included within each reported measure of segment profit or loss, and the title and position of the entity’s CODM. The amendments in this update also require entities to provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. ASU 2023-07 was effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Amendments in this update are required to be applied retrospectively to all periods presented in the financial statements, unless it is impracticable. The adoption of ASU 2023-07 did not have a material impact on the Company's financial statements and disclosures.

The Company has reviewed all other recently issued accounting pronouncements and concluded that such pronouncements are either not applicable to the Company or no material impact is expected in the consolidated financial statements as a result of future adoption.

4. Asset acquisition and redeemable preferred stock

Lins Acquisition

On August 2, 2024, the Company acquired 100% of the outstanding equity interest of Usina Termeletrica de Lins S.A. ("Lins"), which owns key rights and permits to develop a combined cycle gas-fired power plant for up to 2.05GW located in the State of Sao Paulo, within the city limits of Lins, Brazil. The purchase consideration consisted of a $2,000 cash payment made at closing in addition to potential future payments contingent on achieving certain milestones of up to $18,500. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments of $8,080 was included as part of the purchase consideration and was recognized in Other non-current liabilities on the

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Consolidated Balance Sheets upon acquisition. The fair value of the derivative liability was $8,401 as of December 31, 2024.

The purchase of Lins has been accounted for as an asset acquisition. As a result, no goodwill was recorded. The total purchase consideration of $10,080 was allocated to permits and authorizations acquired and is recorded within Intangible assets, net on the Consolidated Balance Sheets. In addition, the Company recognized a deferred tax liability of $4,163 that resulted from the acquisition.

PortoCem Acquisition

On March 20, 2024, the Company completed transactions pursuant to an agreement among the Company, Ceiba Energy Fundo de Investimento em Participações Multiestratégia - Investimento no Exterior (“Ceiba Energy”) and PortoCem Geração de Energia S.A., a wholly-owned subsidiary of Ceiba Energy (“PortoCem”), pursuant to which the Company issued to Ceiba Energy 96,746 shares of 4.8% Series A Convertible Preferred Stock of the Company (the “Series A Convertible Preferred Stock”), and assumed certain of PortoCem’s existing indebtedness in exchange for all outstanding equity interests in PortoCem, the owner of a 15-year 1.6GW capacity reserve contract in Brazil (the “PortoCem Acquisition”).

The PortoCem Acquisition was accounted for as an asset acquisition. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $592 were included in the purchase consideration. The total purchase consideration of $162,860, which was comprised of the value of the Series A Convertible Preferred Stock issued, PortoCem BTG Loan assumed (defined in Note 20) and deferred tax liability of $37,662 recognized as a result of the acquisition, was allocated to acquired capacity reserve contract within Intangible assets, net.

On October 1, 2024, the Company issued to Ceiba Energy 96,746 shares of the Company’s 4.8% Series B Convertible Preferred Stock, par value $0.01 per share and liquidation preference $1,000 per share (the “Series B Convertible Preferred Stock”), in exchange for all outstanding shares of the Company’s Series A Convertible Preferred Stock. The Company analyzed the exchange based on the change in fair value and determined that the exchange resulted in a substantial change and therefore should be accounted for as an extinguishment. Accordingly, the Company recognized a deemed dividend of $10,833 as the difference between the fair value of the Series B Convertible Preferred Stock issued of $107,388 and the carrying value of the Series A Convertible Preferred Stock prior to the exchange of $96,555. Subsequent to the exchange, the Company's Equity Offering (defined in Note 25) triggered an adjustment to the conversion price. The Company recognized the effect of the down round feature of $6,772 as a deemed dividend and increased Additional paid-in capitial based on the difference between the fair values of the Series B Convertible Preferred Stock using the initial conversion price and the reduced conversion price.

Series B Convertible Preferred Stock

The Series B Convertible Preferred Stock was issued with substantially consistent terms as the Series A Convertible Preferred Stock, with the exceptions of the conversion price and the dividend rate adjustment as described below.

The Series B Convertible Preferred Stock has a liquidation preference of $1,000 per share and is not subject to any sinking fund. The Series B Convertible Preferred Stock has no stated maturity and will remain outstanding indefinitely unless redeemed or repurchased by the Company or converted into shares of Class A common stock.

Dividend rights

The Series B Convertible Preferred Stock ranks senior to the shares of the Company’s common stock, in terms of dividend rights and rights upon any voluntary or involuntary liquidation, dissolution or winding up of the Company. Holders of Series B Convertible Preferred Stock are entitled to a cumulative dividend at the rate of 4.8% per annum, which is payable quarterly in arrears. If the Company does not declare and pay a dividend, the dividend rate will increase to 9.8% per annum until all accrued but unpaid dividends have been paid in full.

Conversion features

The Series B Convertible Preferred Stock may be converted by each holder, in whole or in minimum increments of 5,000 shares, at any time into a number of shares of Class A common stock per share of Series B Convertible Preferred Stock equal to the quotient of $1,000 per share plus any accumulated and unpaid dividends thereon and the then applicable

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conversion price. The initial conversion price is $9.96 per share of Class A common stock, subject to customary anti-dilution adjustments.

In December 2024, holders of Series B Convertible Preferred Stock submitted a conversion notice to convert 15,000 shares of Series B Convertible Preferred Stock into 1,673,374 Class A common shares at a conversion price of $9.06 per share. These common shares were issued in January 2025. The Company recorded a reclassification of $16,619 from mezzanine equity to permanent equity as the conversion notice is irrevocable. These Class A common shares are included in the outstanding shares in the Company's EPS calculation.

Redemption rights

Upon the occurrence of certain events, the holders constituting at least a majority of the outstanding voting power of the Series B Convertible Preferred Stock may require the Company to repurchase the Series B Convertible Preferred Stock, in whole but not in part, for cash or shares of Class A common stock (or any combination thereof) at a repurchase price of $1,000 per share plus any accumulated and unpaid dividends thereon. Contingent events that would allow the holders to require repurchase by the Company include:

•change in control, downgrade in the credit rating of certain of the Company's debt or if certain financial leverage ratios aren't achieved ("Change Event").

•as of the 30th trading day following March 20, 2027, if the arithmetic average of the daily volume-weighted average price of the Company's common stock for the thirty consecutive trading day period beginning on first trading day following March 20, 2027 is less than the then-applicable conversion price ("Share Price Condition").

If the Series B Convertible Preferred Stock is to be repurchased by the Company, the majority of the holders of the Series B Convertible Preferred Stock may require the Company to repurchase the Series B Convertible Preferred Stock for shares of Class A common stock.

The Series B Convertible Preferred Stock may be redeemed by the Company, in whole but not in part, at its option upon 45 days’ written notice as follows:

•on or before March 20, 2027 at a redemption price equal to the greater of (i) $1,000 per share plus any accumulated and unpaid dividends and (ii) the cash amount necessary per share for a holder to achieve a Return on Investment (as defined in the Certificate of Designations) as of the redemption date equal to 1.4;

•after the 30th trading day following March 20, 2027 if the Share Price Condition is not met or (y) 30 calendar days after the delivery of the required notice if the Share Price Condition is met, in each case, at a redemption price equal to $1,000 per share plus any accumulated and unpaid dividends;

•occurrence of a Change Event at a redemption price equal to $1,000 per share plus any accumulated and unpaid dividends.

The Company may redeem the Series B Convertible Preferred Stock for cash or shares of Class A common stock (or any combination thereof); provided that for a redemption prior to March 20, 2027 due to a Change Event, a majority of the holders of the Series B Convertible Preferred Stock may require the Company to redeem for cash or shares of Class A common stock.

Since the redemption of the Series B Convertible Preferred Stock is contingently redeemable and therefore not certain to occur, the Series B Convertible Preferred Stock is not required to be classified as a liability. The Series B Convertible Preferred Stock is redeemable at the option of the holder in certain circumstances upon the occurrence of an event that is not solely within the Company's control, and as such, the Series B Convertible Preferred Stock is classified as mezzanine equity on the Consolidated Balance Sheets.

Voting rights

Holders of Series B Convertible Preferred Stock are generally entitled to vote with the holders of common stock on an as-converted basis. Holders of Series B Convertible Preferred Stock are entitled to a separate class vote with respect to

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amendments to the Company’s organizational documents that adversely affect the rights, preferences or voting powers of the Series B Convertible Preferred Stock.

5. Dispositions

Turbine sale

In March 2024, the Company completed a series of transactions that included the sale of turbines and related equipment to the Puerto Rico Electric Power Authority ("PREPA") under an Asset Purchase Agreement ("APA"). The Company deployed this equipment in 2023 in response to a request to provide emergency power to stabilize the power grid in Puerto Rico. The purchase price was $306,599. Additionally, the APA includes a requirement that the Company provide major maintenance services on certain of the sold turbines within 12 months of the sale date; the standalone selling price of these maintenance services of $15,330 will be recognized when these services are performed, and the transaction price allocated to the sale of turbines was reduced by this amount. The Company recognized $3,830 of the maintenance services revenue during the year ended December 31, 2024. The book value of the turbines and equipment at the time of sale was $368,799, and the Company recognized a loss of $77,562 in Loss on sale of assets, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

A portion of the assets sold to PREPA were previously leased by the Company. To facilitate the sale of these leased turbines, the Company terminated leases, acquiring turbines and equipment immediately prior to the sale of such turbines and equipment to PREPA. The cost to acquire the leased turbines, including the write-off of the right-of-use asset and lease liability were included in the book value of the turbines and the related loss upon sale.

As part of these transactions, the Company repaid the Equipment Notes (See Note 20) that were collateralized by the sold turbines, recognizing a loss on extinguishment of debt of $7,879, which was comprised of fees due upon prepayment as well as the unamortized portion of financing costs incurred at the inception of the loan.

The Company's contract to provide emergency power services to support the grid stabilization project was also terminated. All unrecognized contract liabilities and cost to fulfil at the time of termination were recognized in the Consolidated Statements of Operations and Comprehensive (Loss) Income (See Note 7). The Company believes that there are remedies available under the customer contract, and is currently pursuing these remedies. As the outcome of this process is uncertain, any transaction price associated with closing this contract has been fully constrained. The Company has been awarded a new gas sale agreement with PREPA under which the Company is providing gas supply to the sold turbines.

Miami Facility

On June 30, 2024, the Company entered into a definitive agreement to sell its LNG liquefaction facility located in Miami (the "Miami Facility") for $62,000, subject to certain purchase price adjustments at close. The assets related to the Miami Facility were classified as held for sale as of June 30, 2024. In conjunction with the classification to held for sale and completion of the sale in the fourth quarter, the Company recognized an impairment loss of $16,016 within Asset impairment expense in the Consolidated Statements of Operations and Comprehensive Income (Loss), which includes the allocation of goodwill to this business disposition of $10,410.

6. Energos Formation Transaction

On August 15, 2022, the Company completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which the Company transferred ownership of 11 vessels to Energos Infrastructure ("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 the Company and one vessel (the Nanook) was not subject to a future NFE charter. The in-place and future charters to the Company 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 the Consolidated Balance Sheets as Property, plant and equipment, and the proceeds are recognized as debt ("Vessel Financing Obligation"). Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by the Company 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. The Company had accounted for the investment in Energos as an

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equity method investment; see Note 13 for further discussion of this investment. In February 2024, the Company sold substantially all of its stake in Energos.

7. Revenue recognition

Operating revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam, and the sale of LNG cargos. Included in operating revenue are LNG cargo sales to customers of $291,000, $618,521, and $1,175,866 for the years ended December 31, 2024, 2023 and 2022, respectively, which included $34,832 from the cargo sales from the Company's first FLNG project in 2024. LNG cargo sales included $332,000 of contract settlements for the year ended December 31, 2023. There were no such contract settlements for the years ended December 31, 2024 and 2022.

The table below summarizes the activity in Other revenue:


	Year Ended December 31,
	2024		2023		2022
Operation and maintenance revenue	$	147,596	$	49,900	$	—
Interest income and other revenue	10,749		26,341		32,469
Total other revenue	$	158,345	$	76,241	$	32,469

Operation and maintenance revenue is recognized by Genera, under its contract for the operation and maintenance of PREPA's thermal generation assets. Operation and maintenance revenue includes a fixed annual fee and reimbursement for pass-through expenses, including payroll expenses of Genera employees, beginning when the contract commenced on July 1, 2023. Amounts recognized in the year ended December 31, 2024 also include $15,707 of variable consideration for incentive fees earned for cost savings realized by PREPA. Variable consideration has been estimated based on the most likely amount method, and the Company includes estimated amounts in the transaction price to the extent it is probable that a significant reversal of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is resolved. The determination of estimated amounts included in the transaction price is based largely upon an assessment of the uncertainties associated with the variable consideration, including the susceptibility of payment to factors outside of the Company’s control. The Company considers all information that is reasonably available, including historical, current and estimates of future performance.

Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of December 31, 2024 and 2023, receivables related to revenue from contracts with customers totaled $330,944 and $331,108, respectively, and were included in Receivables, net on the Consolidated Balance Sheets, net of current expected credit losses of $13,629 and $1,158, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent leases, which are accounted for outside the scope of ASC 606.

Contract assets include unbilled amounts resulting from contracts with variable considerations, in which the performance obligation is satisfied and revenue is recognized. The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The contract assets and contract liabilities balances as of December 31, 2024 and 2023 are

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detailed below:


	December 31, 2024		December 31, 2023
Contract assets, net - current	$	44,902	$	8,714
Contract assets, net - non-current	20,270		19,901
Total contract assets, net	$	65,172	$	28,615

Contract liabilities, net - current	$	14,415	$	65,287
Contract liabilities, net - non-current	11,750		31,698
Total contract liabilities, net	$	26,165	$	96,985

Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year	$	82,454	$	12,748

Contract assets are presented net of expected credit losses of $158 and $326 as of December 31, 2024 and 2023, respectively.

Contract liabilities decreased in 2024 due to the termination of the Company's contract to support the grid stabilization project in Puerto Rico (Refer to Note 5). Deferred revenue at the time of termination of $43,577 was recognized as Operating revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

The Company has recognized costs to fulfill contracts with customers, which primarily consist of expenses required to enhance resources to deliver under agreements with these customers. These costs can include set-up and mobilization costs incurred ahead of the service period, and such costs will be recognized on a straight-line basis over the expected term of the agreement. As of December 31, 2024, the Company has capitalized $22,797, of which $2,205 of these costs is presented within Prepaid expenses, net and other current assets, net and $20,592 is presented within Other non-current assets, net on the Consolidated Balance Sheets. As of December 31, 2023, the Company had capitalized $25,282, of which $2,864 of these costs was presented within Prepaid expenses and other current assets, net and $22,418 was presented within Other non-current assets, net on the Consolidated Balance Sheets.

In addition to the revenue recognized under ASC 606 as discussed above, in the fourth quarter of 2024, the Company novated an LNG supply contract to a customer, and the Company received $295,558 in 2024, including a prepayment of $60,000 that was received in the third quarter of 2024. As this payment was non-refundable and relieved the Company of a portion of its guarantee obligation under this arrangement (Note 21), these payments were recognized as contract novation income with the revenue and income caption in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

Transaction price allocated to remaining performance obligations

Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.

The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements represents the fixed margin

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multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period:


Period	Revenue
2025	$	362,657
2026	709,063
2027	707,329
2028	691,558
2029	677,365
Thereafter	9,120,982
Total	$	12,268,954

For all other sales contracts that have a term exceeding one year, the Company has elected the practical expedient in ASC 606. Under this expedient, the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. For these excluded contracts, the sources of variability are (a) the market index prices of natural gas used to price the contracts, and (b) the variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG, natural gas, power or steam. As each unit of LNG, natural gas, power or steam represents a separate performance obligation, future volumes are wholly unsatisfied.

Lessor arrangements

Vessels that are chartered to customers under operating leases are recognized within Vessels in Note 15. Vessels included in the Energos Formation Transaction, including those vessels chartered to third parties, continue to be recognized on the Consolidated Balance Sheets, and as such, the carrying amount of these vessels that are leased to third parties under operating leases is as follows:


	December 31, 2024		December 31, 2023
Property, plant and equipment	$	602,192	$	686,683
Accumulated depreciation	(83,135)		(69,977)
Property, plant and equipment, net	$	519,057	$	616,706

The components of lease income from vessel operating leases for the years ended December 31, 2024, 2023 and 2022 are shown below. As the Company has not recognized the sale of all of the vessels included in the Energos Formation Transaction, the operating lease income shown below for the years ended December 31, 2024, 2023, and 2022 respectively, includes revenue from third-party charters of vessels included in the Energos Formation Transaction.


	December 31, 2024		December 31, 2023		December 31, 2022
Operating lease income	$	194,913	$	276,113	$	328,366
Variable lease income	17,696		730		22,940
Total operating lease income	$	212,609	$	276,843	$	351,306

Prior to the completion of the Energos Formation Transaction, the Company's charter of the Nanook was accounted for as a finance lease, and the Company recognized interest income of $28,643 for the year ended December 31, 2022, related to the finance lease, which was presented within Other revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The Company also recognized revenue of $5,852 for the year ended December 31, 2022, related to the operation and services agreement and variable charter revenue within Vessel charter revenue in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

The Company recognized the sale of the net investment in the finance lease of the Nanook as part of the Energos Formation Transaction. Proceeds of $593,000 were allocated to the sale of this financial asset, and upon derecognition of the finance

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lease, a loss of $14,598 was recognized as Other expense (income), net, in the Consolidated Statements of Operations and Comprehensive (Loss) Income for the year ended December 31, 2022.

Subsequent to the Energos Formation Transaction, all cash receipts on long-term vessel charters will be received by Energos. As such, future cash receipts from both operating leases and finance leases were not significant as of December 31, 2024.

8. Leases, as lessee

The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability.

The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations resulting from changes in inflation indices and market adjustments, as well as other lease costs that depend on the use of the underlying asset, are not considered lease payments when calculating the lease liability or ROU asset. Instead, such payments are accounted for as variable lease cost when the condition that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.

As of December 31, 2024 and 2023, ROU assets, current lease liabilities and non-current lease liabilities consisted of the following:


	December 31, 2024		December 31, 2023
Operating right-of-use assets	$	599,937	$	538,055
Finance right-of-use assets (1)	18,796		50,330
Total right-of-use assets	$	618,733	$	588,385

Current lease liabilities:
Operating lease liabilities	$	124,391	$	135,867
Finance lease liabilities	3,971		28,681
Total current lease liabilities	$	128,362	$	164,548
Non-current lease liabilities:
Operating lease liabilities	$	471,961	$	390,519
Finance lease liabilities	3,200		15,975
Total non-current lease liabilities	$	475,161	$	406,494

(1)Finance lease ROU assets are recorded net of accumulated amortization of $8,134 and $21,470 as of December 31, 2024 and 2023, respectively.

During 2024, the Company terminated the finance lease of certain turbines and purchased the turbines. Immediately subsequent to the purchase of the turbines, the assets were sold as part of the sale of assets to PREPA (Refer to Note 5). The termination of the lease resulted in the write-off of the right-of-use asset and lease liability of $23,431 and $29,443, respectively, which was included in the book value of the turbines and the related loss upon sale.

In addition, the Company terminated the operating lease of three turbines during 2024. The termination of the lease resulted in the write-off of the right-of-use asset and lease liability of $21,821 and $25,762 respectively, and a loss on lease termination of $4,789 recognized within Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

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For the years ended December 31, 2024, 2023, and 2022, the Company’s operating lease cost recorded within the Consolidated Statements of Operations and Comprehensive (Loss) Income was as follows:


	Year Ended December 31,
	2024		2023		2022
Fixed lease cost	$	161,830	$	109,873	$	75,771
Variable lease cost	2,984		4,601		2,203
Short-term lease cost	8,603		23,903		20,129

Lease cost - Cost of sales	$	147,539	$	88,608	$	87,610
Lease cost - Operations and maintenance	17,961		42,520		3,681
Lease cost - Selling, general and administrative	7,917		7,249		6,812

For the years ended December 31, 2024, 2023 and 2022, the Company has capitalized $36,288, $61,320 and $20,403 of lease costs, respectively. Capitalized costs include vessels and port space used during the commissioning of development projects. Short-term lease costs for vessels chartered by the Company to transport inventory from a supplier’s facilities to the Company’s storage locations are capitalized to inventory.

The Company has leases of ISO tanks and a parcel of land that are recognized as finance leases. For the years ended December 31, 2024, 2023 and 2022, the Company’s finance interest expense and amortization recorded in Interest expense and Depreciation and amortization, respectively, within the Consolidated Statements of Operations and Comprehensive (Loss) Income were as follows:


	Year Ended December 31,
	2024		2023		2022
Interest expense related to finance leases	$	981	$	3,706	$	852
Amortization of right-of-use asset related to finance leases	6,132		19,337		1,512

Cash paid for operating leases is reported in operating activities in the Consolidated Statements of Cash Flows. Supplemental cash flow information related to leases was as follows for the years ended December 31, 2024, 2023 and 2022:


	Year Ended December 31,
	2024		2023		2022
Operating cash outflows for operating lease liabilities	$	175,862	$	133,132	$	96,698
Financing cash outflows for finance lease liabilities	9,500		21,187		3,697
Right-of-use assets obtained in exchange for new operating lease liabilities	206,344		265,537		135,075
Right-of-use assets obtained in exchange for new finance lease liabilities	—		47,672		—

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The future payments due under operating and finance leases as of December 31, 2024 are as follows:


	Operating Leases		Financing Leases
2025	$	175,222	$	4,263
2026	110,417		2,592
2027	110,468		89
2028	109,062		89
2029	85,023		89
Thereafter	240,447		763
Total Lease Payments	$	830,639	$	7,885
Less: effects of discounting	234,287		714
Present value of lease liabilities	$	596,352	$	7,171

Current lease liability	$	124,391	$	3,971
Non-current lease liability	471,961		3,200

As of December 31, 2024, the weighted-average remaining lease term for operating leases was 6.8 years and finance leases was 3.0 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of December 31, 2024 and 2023 was 10.3% and 10.1%, respectively. The weighted average discount rate associated with finance leases as of December 31, 2024 and 2023 was 5.2% and 8.2%, respectively.

9. Financial instruments

Commodity risk management

The Company has utilized commodity swap transactions to manage exposure to changes in market pricing of natural gas or LNG. Realized and unrealized gains and losses on these transactions have been recognized in Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

•During the fourth quarter of 2022, the Company entered into a commodity swap transaction to swap market pricing exposure for approximately 6.8 TBtus for a fixed price of $40.55 per MMBtu. The swap settled during the first quarter of 2023 resulting in a gain of $41,315 recognized as a reduction to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The gain was comprised of a realized gain of $146,112 and the reversal of the unrealized gain of $104,797 recognized in the fourth quarter of 2022.

•In January 2023, the Company entered into a series of commodity swap transactions. Realized losses of $8,495 for the year ended December 31, 2023 on these instruments have been recognized in Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. All swaps were settled prior to December 31, 2023.

Interest rate and currency risk management

During 2023, the Company entered into a non-deliverable forward to secure the currency position of the Barcarena Debentures (defined below) which is denominated in U.S. dollars. The forward was settled, and the Company recorded a realized gain of $5,864 for the year ended December 31, 2023.

During 2024, the Company entered into a series of foreign exchange forward contracts and zero-cost collars to reduce exchange rate risk associated with U.S. dollar borrowings and expected capital expenditures. As of December 31, 2024, the notional amount of outstanding foreign exchange contracts was approximately $211,547. These instruments are expected to settle through the third quarter of 2026. The Company recognized unrealized gains, net of $22,085 for the year ended

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December 31, 2024 for these foreign currency contracts. The Company also recognized realized gains of $5,087 upon settlement of a portion of the foreign exchange contracts during the year ended December 31, 2024.

The Company does not hold or issue instruments for speculative purposes, and the counterparties to such contracts are major banking and financial institutions. Credit risk exists to the extent that the counterparties are unable to perform under the contracts; however, the Company does not anticipate non-performance by any counterparties.

The mark-to-market gain or loss on the interest rate swap, non-deliverable forward and other foreign exchange derivative instruments that are not intended to mitigate commodity risk are reported in Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

Embedded contingent interest derivative

During 2024, the Company entered into a side letter with lenders in the Term Loan A Credit Agreement (defined below), under which the Company's interest on the Term Loan A (defined below) would increase by 2% if the lenders demand that the Company pursue a refinancing of the Term Loan A and the Company is not able to successfully refinance. This contingent interest feature meets the definition of a derivative and requires bifurcation from the debt host contract. Changes to the fair value of this derivative are recognized within Interest expense, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

Fair value

Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:

•Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.

•Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.

•Level 3 – unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.

The valuation techniques that may be used to measure fair value are as follows:

•Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.

•Cost approach – based on the amount that currently would be necessary to replace the service capacity of an asset (replacement cost).

The Company uses the market approach when valuing investment in equity securities and foreign exchange forward contracts which are recorded in Prepaid expenses and other current assets, net, Other non-current assets, net and Other current liabilities on the Consolidated Balance Sheets as of December 31, 2024 and 2023.

The Company uses the income approach for valuing the contingent consideration derivative liabilities and embedded contingent interest derivative. The contingent consideration derivative liabilities represent consideration due to the sellers in asset acquisitions when certain contingent events occur and are recorded within Other current liabilities and Other long-term liabilities based on the timing of expected settlement. The embedded contingent interest derivative represents incremental interest payments due to the lenders when certain contingent events occur and is recorded within Other current liabilities and Other long-term liabilities based on the timing of expected payments.

The fair value of derivative instruments is estimated considering current interest rates, foreign exchange rates, closing quoted market prices and the creditworthiness of counterparties. The Company estimates fair value of the contingent consideration derivative liabilities using a discounted cash flows method with discount rates based on the average yield

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curve for bonds with similar credit ratings and matching terms to the discount periods as well as a probability of the contingent events occurring. The Company estimates fair value of the embedded contingent interest derivative using a discounted cash flows method with discount rate based on the effective interest rate for the debt host instrument as well as a probability of the contingent events occurring.

The following table presents the Company’s financial assets and financial liabilities, including those that are measured at fair value, as of December 31, 2024 and 2023:


	Level 1		Level 2		Level 3		Total
December 31, 2024
Assets
Investment in equity securities	$	—	$	—	$	8,678	$	8,678
Foreign exchange contracts	—		22,055		—		22,055

Liabilities
Foreign exchange contracts	—		1,168		—		1,168
Contingent consideration derivative liabilities	—		—		41,984		41,984
Embedded contingent interest derivative	—		—		10,629		10,629

December 31, 2023
Assets
Investment in equity securities	$	—	$	—	$	7,678	$	7,678

Liabilities
Contingent consideration derivative liabilities	—		—		37,832		37,832

The Company believes the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximated their fair value as of December 31, 2024 and 2023 and are classified as Level 1 within the fair value hierarchy.

The table below summarizes the fair value adjustment to instruments measured at Level 3 in the fair value hierarchy. The adjustments to contingent consideration derivative liabilities and embedded contingent interest derivative for the years ended December 31, 2024, 2023 and 2022 are shown below:


	Year Ended December 31,
	2024		2023		2022
Contingent consideration derivative liabilities - Fair value adjustment - (gain) loss	$	(1,959)	$	(4,801)	$	703
Embedded contingent interest derivative - Fair value adjustment - loss	1,798		—		—

During the years ended December 31, 2024 and 2023, the Company had no transfers in or out of Level 3 in the fair value hierarchy. During the first quarter of 2024, the Company sold substantially all of its investment in Energos; this investment had been accounted for as an equity method investment (Note 13). The Company retained an investment in Energos valued at $1,000, which is shown as a Level 3 investment in equity securities in the table above.

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10. Restricted cash

As of December 31, 2024 and 2023, restricted cash consisted of the following:


	December 31, 2024		December 31, 2023
Cash restricted under the terms of loan agreements	$	422,098	$	102,079
Collateral for letters of credit and performance bonds	50,598		53,321
Total restricted cash	$	472,696	$	155,400

Uses of cash proceeds under the BNDES Term Loan, Barcarena Debentures and PortoCem Debentures (see Note 20) are restricted to certain payments to construct the Company's power plants in Brazil.

11. Inventory

As of December 31, 2024 and 2023, inventory consisted of the following:


	December 31, 2024		December 31, 2023
LNG and natural gas inventory	$	67,232	$	75,417
Automotive diesel oil inventory	7,934		10,121
Bunker fuel, materials, supplies and other	28,058		28,146
Total inventory	$	103,224	$	113,684

Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The Company recognized an adjustment to inventory of $6,232 during the year ended December 31, 2023. In the second quarter of 2023, the Company acquired a spot cargo at a higher cost to obtain a new customer contract (Note 29), and the net realizable value of this cargo was below the cost. No inventory adjustments were recognized during the years ended December 31, 2024 or December 31, 2022.

12. Prepaid expenses and other current assets

As of December 31, 2024 and 2023, prepaid expenses and other current assets consisted of the following:


	December 31, 2024		December 31, 2023
Prepaid expenses	$	28,667	$	31,490
Recoverable taxes	98,101		80,630
Contract assets (Note 7)	44,902		8,714
Due from affiliates	2,627		1,566
Assets held for sale	—		21,265
Other current assets	31,199		69,439
Total prepaid expenses and other current assets, net	$	205,496	$	213,104

During 2023, the Company began to sub-charter the Winter, a vessel included in the Energos Formation Transaction, and an asset was recorded representing the existing charterer's remaining payments to Energos, which was $59,074 as of December 31, 2023. The Company also recognized a liability of $49,400 as of December 31, 2023 (see Note 19) representing the Company's obligation to pay sub-charter payments until the vessel is chartered directly from Energos. The sub-charter was terminated during the third quarter of 2024, and the Company derecognized both the sub-charter asset and liability.

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The remaining balance of other current assets as of December 31, 2024 and 2023 primarily consists of derivative assets recognized for foreign currency exchange contracts (Note 9) and deposits.

Assets held for sale

In December 2023, the Company entered into an agreement to sell the vessel, Mazo, for $22,400; and as such, the vessel was classified as held for sale as of December 31, 2023. In conjunction with the classification to held for sale, the Company recognized an impairment of $10,958 within Asset impairment expense in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Nonrecurring, Level 2 inputs were used to estimate the fair value of the vessel for the purpose of recognizing the impairment. The sale closed in 2024, resulting in a gain of $392.

13. Equity method investments

Changes in the balance of the Company’s equity method investments are as follows:


	December 31, 2024		December 31, 2023
Equity method investments as of beginning of period	$	137,793	$	392,306
Capital contributions	6,794		1,501
Dividends	—		(5,830)
Equity in earnings of investees	—		15,249
Other-than-temporary impairment	—		(5,277)
Sale of equity method investments	(144,587)		(260,156)
Equity method investments as of end of period	$	—	$	137,793

At December 31, 2023, the carrying value of the Company’s equity method investments was less than its proportionate share of the underlying net assets of its investees by $5,277.

Energos

In August 2022, the Company completed a transaction with an affiliate of Apollo Global Management, Inc., pursuant to which the Company transferred ownership of 11 vessels to Energos Infrastructure ("Energos") in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos (the “Energos Formation Transaction”). The Company's equity investment provided certain rights, including representation on the Energos board of directors, that gave the Company significant influence over the operations of Energos, and as such, the investment was accounted for under the equity method. Energos was also an affiliate, and all transactions with Energos were transactions with an affiliate.

In February 2024, the Company sold substantially all of its stake in Energos. As a result of the transaction, the Company has recognized an other than temporary impairment ("OTTI") of the investment in Energos totaling $5,277 for the year ended December 31, 2023, and this loss was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Nonrecurring, Level 2 inputs were used to estimate the fair value of the investment for the purpose of recognizing the OTTI. The sale was completed on February 14, 2024 and the Company received proceeds of $136,365, resulting in a loss of $7,222 presented within Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The Company retained an investment in Energos valued at $1,000, which has been recognized within Other non-current assets. Following the disposition of substantially all of the stake in Energos, the Company no longer has significant influence over Energos.

Due to the timing and availability of financial information of Energos, the Company recognized its proportional share of the income or loss from the equity method investment on a financial reporting lag of one fiscal quarter. For the years ended December 31, 2023 and 2022, the Company has recognized earnings from Energos of $9,263 and $2,788, respectively. There were no earnings from Energos for the year ended December 31, 2024.

Hilli LLC

On March 15, 2023, the Company completed a transaction with Golar LNG Limited ("GLNG") for the sale of the Company's investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and

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$100,000 in cash (the "Hilli Exchange"). In the fourth quarter of 2022, the Company recognized an OTTI on the investment in Hilli LLC of $118,558; this impairment was recognized in Income (loss) from equity method investments in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Upon completion of the Hilli Exchange, a loss on disposal of $37,401 was recognized in Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. As a result of the Hilli Exchange, the Company no longer has an ownership interest in the Hilli. NFE shares received from GLNG were cancelled upon closing of the Hilli Exchange.

14. Construction in progress

The Company’s construction in progress activity during the years ended December 31, 2024 and 2023 is detailed below:


	December 31, 2024		December 31, 2023
Construction in progress as of beginning of period	$	5,348,294	$	2,418,608
Additions	2,247,592		3,438,895

Impact of currency translation adjustment	(196,854)		30,989
Assets placed in service	(3,824,643)		(540,198)
Construction in progress as of end of period	$	3,574,389	$	5,348,294

Interest expense of $486,396, $295,809 and $94,454, inclusive of amortized debt issuance costs, was capitalized for the years ended December 31, 2024, 2023 and 2022, respectively. Recoverable taxes of $45,996 were capitalized for the year ended December 31, 2024 and represents non-cash addition to Construction in progress.

The Company's first Fast LNG project was placed into service for accounting purposes in the fourth quarter of 2024, and $3,573,382 was transferred to Property, plant and equipment, net. Assets placed in service during 2024 also include the Company's LNG receiving facility located on the southern coast of Brazil (the “Santa Catarina Facility”).

The Company has significant development activities in Latin America. The successful completion of these development projects is subject to various risks, such as obtaining government approvals, identifying suitable sites, securing financing and permitting, and ensuring contract compliance.

15. Property, plant and equipment, net

As of December 31, 2024 and 2023, the Company’s property, plant and equipment, net consisted of the following:


	December 31, 2024		December 31, 2023
LNG liquefaction facilities	$	3,316,504	$	63,316
Vessels	1,575,299		1,494,433
Terminal and power plant equipment	630,822		668,927
Gas pipelines	323,196		66,319
Power facilities	283,470		273,978
ISO containers and other equipment	66,766		97,984
Land	51,897		54,324
Leasehold improvements	49,862		139,967
Accumulated depreciation	(455,009)		(377,833)
Total property, plant and equipment, net	$	5,842,807	$	2,481,415

LNG liquefaction facilities includes the Company's first Fast LNG project, which was placed into service in the fourth quarter of 2024.

The book value of the vessels that was recognized due to the failed sale leaseback in the Energos Formation Transaction as of December 31, 2024 and 2023 was $1,272,334 and $1,293,384, respectively.

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Depreciation expense for the years ended December 31, 2024, 2023 and 2022 totaled $144,166, $141,069 and $104,823, respectively, of which $511, $905 and $954, respectively, is included within Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

16. Goodwill and intangible assets

Goodwill

The Company allocated $10,410 of goodwill from the Terminal and Infrastructure Reporting unit to the sale of the Miami Facility disposal group during the year ended December 31, 2024 on a relative fair value basis. As of December 31, 2024 and December 31, 2023, the carrying amount of goodwill within the Terminals and Infrastructure reporting unit and Ships reporting unit was $750,412 and $15,938, and $760,822 and $15,938, respectively.

The Company performed a quantitative analysis as of October 1, 2024 and a qualitative analysis as of October 1, 2023. The Company concluded that the fair value of each reporting unit was greater than the carrying amount for both periods, and no goodwill impairment charges were recognized during the years ended December 31, 2024 and 2023.

Intangible assets

The following tables summarize the composition of intangible assets as of December 31, 2024 and 2023:


	December 31, 2024
	Gross Carrying Amount		Accumulated Amortization		Currency Translation Adjustment		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Acquired capacity reserve contract	$	162,045	$	(5,942)	$	(31,301)	$	124,802	17
Favorable vessel charter contracts	17,700		(14,942)		—		2,758		4
Permits and development rights	61,894		(6,417)		(5,793)		49,684		34

Easements	1,555		(392)		—		1,163		30

Indefinite-lived intangible assets
Easements	1,191		—		(88)		1,103		n/a
Total intangible assets	$	244,385	$	(27,693)	$	(37,182)	$	179,510


	December 31, 2023
	Gross Carrying Amount		Accumulated Amortization		Currency Translation Adjustment		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Favorable vessel charter contracts	$	17,700	$	(10,615)	$	—	$	7,085	4
Permits and development rights	48,217		(5,557)		(291)		42,369		38
Easements	1,555		(341)		—		1,214		30

Indefinite-lived intangible assets
Easements	1,191		—		(44)		1,147		n/a
Total intangible assets	$	68,663	$	(16,513)	$	(335)	$	51,815

As of December 31, 2024 and 2023, the weighted-average remaining amortization periods for the intangible assets were 19.7 and 28.8 years, respectively. Amortization expense for the years ended December 31, 2024, 2023, and 2022 was $12,227, $26,853, and $37,162, respectively which were inclusive of reductions in expense for the amortization of unfavorable contract liabilities.

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During the year ended December 31, 2023, certain favorable vessel charter contract intangibles with a gross carrying amount of $88,000 became fully amortized, and the gross carrying amount and accumulated amortization have been written-off. Additionally, a vessel charter contract was terminated during 2023, and the net book value of the intangible asset on the date of termination of $9,553 was recognized as an impairment in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

In the third quarter of 2023, An Bord Pleanála ("ABP"), Ireland's planning commission, denied the Company's application for the development of an LNG terminal and power plant in Shannon, Ireland. The Company challenged this decision, and in September 2024, the High Court of Ireland ruled that ABP did not have appropriate grounds for the denial of the permit. In November, ABP sought leave to appeal the High Court's decision, the High Court has not yet heard the request to leave appeal. If the leave is not granted, then ABP will be directed to reconsider our permit application on accordance with Irish Law. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect to the Company's results of operations.

The estimated aggregate amortization expense for each of the next five years is:


Year ended December 31:
2025	$	12,312
2026	9,553
2027	9,553
2028	9,553
2029	9,553
Thereafter	127,883
Total	$	178,407

17. Other non-current assets, net

As of December 31, 2024 and 2023, Other non-current assets consisted of the following:


	December 31, 2024		December 31, 2023

Long term receivables	$	114,677	$	—
Contract asset, net (Note 7)	20,270		19,901

Cost to fulfill (Note 7)	20,592		22,418
Financing costs	57,568		11,923
Other	59,792		72,661
Total other non-current assets	$	272,899	$	126,903

In the fourth quarter of 2024, the Company novated an LNG supply contact to a customer (Note 7). In conjunction with this novation, the Company agreed to guarantee the performance of the LNG supplier (Note 21). In exchange for this guarantee, the Company will receive payments totaling $126,668 from the counterparty. These payments will be made between the third quarter of 2026 through the first quarter of 2028, and the discounted value of the payment stream of $114,677 has been recorded as a long-term receivable.

Financing costs includes deferred costs associated with the Company's Revolving Facility and the undrawn portion of the Term Loan A (both defined below). Other non-current assets includes the development costs for hosted software products, foreign exchange contracts and investments in equity securities, which includes investments without a readily determinable fair value of $8,678 and $7,678 as of December 31, 2024 and 2023, respectively. The Company has not recognized any gains or losses in the value of these investments during 2024.

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18. Accrued liabilities

As of December 31, 2024 and 2023, Accrued liabilities consisted of the following:


	December 31, 2024		December 31, 2023
Accrued development costs	$	113,193	$	286,030
Accrued interest	84,566		82,507
Accrued inventory	93,319		4,855
Accrued bonuses	37,415		41,356
Other accrued expenses	62,866		56,927
Total accrued liabilities	$	391,359	$	471,675

19. Other current liabilities

As of December 31, 2024 and 2023, Other current liabilities consisted of the following:


	December 31, 2024		December 31, 2023
Derivative liabilities	$	29,417	$	19,450
Contract liabilities (Note 7)	14,415		65,287
Income tax payable	88,607		54,040
Due to affiliates	11,530		9,579
Winter sub-charter liability	—		49,400
Other current liabilities	30,860		30,195
Total other current liabilities	$	174,829	$	227,951

During the fourth quarter of 2023, the Company began to sub-charter the Winter, a vessel included in the Energos Formation Transaction, and a liability was recorded representing the Company's obligation to pay sub-charter payments until the vessel is chartered directly from Energos. The Company also recognized an asset of $59,074 (see Note 12) representing the charterer's remaining payments to Energos. The sub-charter was terminated during the third quarter of 2024, and the Company derecognized both the sub-charter asset and liability.

The remaining balance of other current liabilities as of December 31, 2024 primarily consists of recoverable taxes payable.

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20. Debt

As of December 31, 2024 and 2023, debt consisted of the following:


	December 31, 2024		December 31, 2023
Corporate debt
Senior Secured Notes, due November 2029	$	2,728,269	$	—
Senior Secured Notes, due September 2026	509,022		1,486,374
Senior Secured Notes, due March 2029	233,789		—
Senior Secured Notes, due September 2025	—		1,245,662
Revolving Facility	1,000,000		866,600
Term Loan B, due October 2028	776,353		771,420
Term Loan A, due July 2027	321,573		—
Short-term Borrowings	179,890		182,270
Sale leaseback financing
Vessel Financing Obligation, due August 2042	1,366,293		1,359,995
Tugboat Financing, due December 2038	46,224		46,728
Asset level financing
PortoCem Debentures, due September 2040	729,259		—
BNDES Term Loan, due October 2045	350,525		—
South Power 2029 Bonds, due May 2029	217,871		216,993
Barcarena Debentures, due October 2028	194,571		175,025
Turbine Financing, due July 2027	142,549		—
EB-5 Loan, due July 2028	98,647		61,614
Barcarena Term Loan, due February 2024	—		199,678
Equipment Notes, due July 2026	—		190,789
Total debt	$	8,894,835	$	6,803,148
Current portion of long-term debt	$	539,132	$	292,625
Long-term debt	8,355,703		6,510,523

Long-term debt is recorded at amortized cost on the Consolidated Balance Sheets. The fair value of the Company's long-term debt was $9,087,890 and $6,835,487 as of December 31, 2024 and 2023, respectively, and was classified as Level 2 within the fair value hierarchy. The Company's debt arrangements include cross-acceleration clauses whereby events of default under an individual debt agreement can lead to acceleration of principal under other debt arrangements.

Our outstanding debt as of December 31, 2024 is repayable as follows:


	December 31, 2024
2025	$	539,132
2026	712,903
2027	1,270,843
2028	1,184,328
2029	3,139,164
Thereafter	2,180,726
Total debt	$	9,027,096

Less: deferred finance charges	(132,261)
Total debt, net deferred finance charges	$	8,894,835

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The Company's future payments for the Vessel Financing Obligation include the expected carrying value of vessels that will be derecognized at the end of the lease term. The future payments also include third-party charter payments that will be received by Energos and included as part of debt service.

2024 Exchange Transactions

On November 6, 2024, the Company entered into an exchange and subscription agreement (the “Exchange and Subscription Agreement”) with certain holders (the “Supporting Holders”) of the Company’s outstanding 2026 Notes and 2029 Notes (each defined below). Pursuant to the Exchange and Subscription Agreement (i) NFE Financing LLC (“NFE Financing”), an indirect subsidiary of NFE, sold to the Supporting Holders approximately $1,210,396 aggregate principal amount of NFE Financing’s 12.0% Senior Secured Notes due 2029 (the “New 2029 Notes”) (the transactions described in clause (i), the “Subscription Transactions”) and (ii) NFE Financing issued to the Supporting Holders approximately $1,519,731 aggregate principal amount of New 2029 Notes in a dollar-for-dollar exchange for a portion of the Company’s 2026 Notes and 2029 Notes (the transactions described in clause (ii), the “Exchange Transactions” and together with the Subscription Transactions, the “Refinancing Transactions”).

NFE Financing issued $2,730,127 aggregate principal amount of New 2029 Notes pursuant to the Refinancing Transactions. The Company utilized $886,648 of these net proceeds from the Subscription Transactions to repay in full the outstanding aggregate principal amount and accrued interest on the 2025 Notes. The remainder of the net proceeds from the New 2029 Notes issued pursuant to the Subscription Transactions will be used for general corporate purposes.

Pursuant to the Exchange and Subscription Agreement, upon consummation of the Refinancing Transactions, the Supporting Holders received a commitment fee equal to either (i) 5% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in shares of Class A common stock of the Company, at a price of $8.63 per share (the “Commitment Fee Shares”), (ii) 2% of the aggregate principal amount of such Supporting Holder’s New 2029 Notes, payable in kind in the form of additional New 2029 Notes (the “Commitment Fee Notes”), or (iii) a combination of the foregoing. The Company has issued 15,700,998 Commitment Fee Shares to the Supporting Holders in satisfaction of its commitment fee obligations under the Exchange and Subscription Agreement, and $5,368 Commitment Fee Notes were issued and included in the total New 2029 Notes issuance.

The New 2029 Notes were issued pursuant to, and are governed by, an indenture (the “New Notes Indenture”). The New 2029 Notes are senior, secured obligations of NFE Financing, and interest is payable semi-annually in arrears at a rate of 12.0% per annum on May 15 and November 15 of each year, beginning on May 15, 2025. The New Notes will mature on November 15, 2029, provided that the maturity date shall be accelerated to the date that is 91 days prior to the stated maturity date of any other indebtedness of the Company, subject to certain exceptions as described in the New Notes Indenture, if more than $100,000 aggregate principal amount of such other indebtedness remains outstanding on such date.

NFE Financing may redeem some or all of the New 2029 Notes at redemption prices set forth in the New Notes Indenture; such redemption prices and any “make-whole” premiums are based on the timing of the redemption. Further, upon the occurrence of certain other events, including change of control and certain distributions from the Company’s Brazil business, NFE Financing may be required to make an offer to repurchase all of the New 2029 Notes at prices specified in the New Notes Indenture.

The New 2029 Notes are guaranteed by NFE Financing’s wholly-owned subsidiary, Bradford County Real Estate Partners LLC (the “New Notes Guarantor”) which owns the Company’s land in Wyalusing, Pennsylvania. The New 2029 Notes are secured by first-priority liens on: (a) all assets of NFE Financing, including approximately 45% of the equity in the entity that owns the Company’s Brazil business, and 100% of the equity in the New Notes Guarantor and (b) all assets of the New Notes Guarantor.

The New Notes Indenture provides for customary events of default which include (subject in certain cases to customary grace and cure periods), among others, acceleration and/or defaults of certain of the Company's other indebtedness. The New Notes Indenture and other credit agreements associated with certain intercompany loans of NFE Financing, limit the ability of the Company to, among other things, incur additional indebtedness, incur liens that secure indebtedness, make restricted payments, create dividend restrictions and other payment restrictions, sell or transfer certain assets, in each case subject to certain exceptions and qualifications set forth in the New Notes Indenture and other indentures.

The repayment of all of the 2025 Notes and the exchange of a portion of the 2026 Notes and 2029 Notes was treated as an extinguishment, and $11,442 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of

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debt in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Fees paid to lenders, including the issuance of Commitment Fee Shares and Commitment Fee Notes, of $193,370 were included in the loss on extinguishment of debt. The Company also recognized $30,541 of loss on extinguishment of debt, which represents the fair value of the New 2029 Notes issued in excess of the carrying amount of debt exchanged or repaid. The New 2029 Notes are recorded at fair value and fees paid to third parties of $32,341 will be amortized over the term of the New 2029 Notes. As of December 31, 2024, total remaining unamortized deferred financing costs for the New 2029 Notes was $31,747.

In conjunction with the Refinancing Transactions, the Supporting Holders agreed to consent to certain amendments to the indentures pursuant to which the 2026 Notes (such indenture, the “Existing 2026 Notes Indenture”) and the 2029 Notes (such indenture, the “Existing 2029 Notes Indenture”) were issued. These amendments allow the Company to subordinate the liens on certain of the collateral securing the obligations under each of the Existing 2026 Notes Indenture and Existing 2029 Notes Indenture to the liens on the same collateral securing certain intercompany loans due to NFE Financing, and to remove all covenants and events of default that may be removed in compliance with terms of such indentures (the “Indenture Amendments”). The adoption of the Indenture Amendments required the consent of holders of at least 66.67% the outstanding principal amount of each of the 2026 Notes and 2029 Notes. The Company received the required level of consent, and subsequently executed a supplemental indenture to the Existing 2026 Notes Indenture (the “2026 Supplemental Indenture”) and a supplemental indenture to the Existing 2029 Notes Indenture (the “2029 Supplemental Indenture,” and, together with the 2026 Supplemental Indenture, the “Supplemental Indentures”) effecting the Amendments. The Supplemental Indentures became effective on December 5, 2024.2025 Notes

In September and December 2020, the Company issued an aggregate amount of $1,250,000 of 6.75% senior secured notes in private offerings pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest was payable semi-annually in arrears on March 15 and September 15 of each year; no principal payments were due until maturity on September 15, 2025.

In connection with the offering of the 2029 Notes (defined below) in March 2024, the Company completed a cash tender offer to repurchase $375,000 of the outstanding 2025 Notes, for an aggregate repurchase price of $376,875. 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 $1,875 was recognized as Loss on extinguishment of debt, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The remaining outstanding principal under the 2025 Notes was repaid in conjunction with the Refinancing Transactions.

2026 Notes

In April 2021, the Company issued $1,500,000 of 6.50% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2026 Notes”). Interest is payable semi-annually in arrears on March 31 and September 30 of each year; no principal payments are due until maturity on September 30, 2026. The Company may redeem the 2026 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

In connection with the issuance of the 2026 Notes, the Company incurred $25,240 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2026 Notes on the Consolidated Balance Sheets. As part of the Refinancing Transactions, the Company exchanged $989,121 of the 2026 Notes on a dollar-for-dollar basis for New 2029 Notes, resulting in a partial extinguishment. This partial extinguishment of the 2026 Notes resulted in the proportionate write-off of unamortized deferred financing fees, and as of December 31, 2024 and 2023, total remaining unamortized deferred financing costs for the 2026 Notes was $1,857 and $13,626, respectively.

2029 Notes

In March 2024, the Company issued $750,000 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. The Company may redeem the 2029 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

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In connection with the issuance of the 2029 Notes, the Company incurred $14,171 in origination, structuring and other fees, which was deferred as a reduction of the principal balance of the 2029 Notes on the Consolidated Balance Sheets. As part of the Refinancing Transactions, the Company exchanged $513,272 of the 2029 Notes on a dollar-for-dollar basis for New 2029 Notes, resulting in a partial extinguishment. This partial extinguishment of the 2029 Notes resulted in the proportionate write-off of unamortized deferred financing fees, and as of December 31, 2024, total remaining unamortized deferred financing costs for the 2029 Notes was $2,939.

Revolving Facility

In April 2021, the Company entered into a credit agreement (the "Revolving Credit Agreement") for a $200,000 senior secured revolving credit facility (the "Revolving Facility"). Through December 31, 2023, the Revolving Facility was amended to increase the borrowing capacity to $950,000. In May 2024, the Company entered into an amendment which increased the borrowing capacity by $50,000, for a total capacity of $1,000,000. The amendments did not impact the interest rate or term of the Revolving Facility, and no deferred costs were written off. As of December 31, 2024 and 2023, $1,000,000 and $866,600 was outstanding under the Revolving Facility.

Concurrent with the Refinancing Transactions, the Company entered into an amendment with certain lenders in the Revolving Facility (the "Consenting Lenders") to extend the maturity of their commitments to October 15, 2027. The Consenting Lenders hold $900,000 of the total revolving commitments. The applicable margin payable on revolving borrowings to the Consenting Lenders increased by 100 basis points. The Company is required to reduce the commitments with proceeds from certain assets sales and by certain amounts received from the settlement of the Company’s claims following the termination of the Company’s contract to provide emergency power services in Puerto Rico (Note 5). Notwithstanding these required reductions, the Company must reduce commitments for Consenting Lenders to $630,000 by September 30, 2025, and as such, $270,000 of the outstanding borrowings under the Revolving Facility have been recognized as current. The remainder of the Revolving Facility will mature in April 2026 with the potential for the Company to extend the maturity date once for a one-year increment.

The obligations under the Revolving Facility are guaranteed by certain of the Company's subsidiaries, including those that own the Company's offshore FLNG facility at Altamira ("FLNG1 Project") and Altamira Onshore Project (defined below), and are secured by substantially the same collateral securing the obligations under certain intercompany loans entered into in conjunction with the Refinancing Transactions, as well as the assets comprising the FLNG1 Project and Altamira Onshore Project. The Company is required to comply with the below covenants under the Revolving Facility and the Letter of Credit Facility (defined below):

•Beginning with the fiscal quarter ended March 31, 2025, for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to EBITDA Ratio must be below the following: (i) 8.75 to 1.00, for the fiscal quarter ending March 31, 2025, (ii) 7.25 to 1.00, for the fiscal quarter ending June 30, 2025, (iii) 6.75 to 1.00, for the fiscal quarter ending September 30, 2025, (iv) 6.50 to 1.00, for the fiscal quarter ending December 31, 2025, (v) 7.25 to 1.00, for the fiscal quarters ending March 31, 2026 through September 30, 2026, and (vi) 6.75 to 1.00, for the fiscal quarter ending December 31, 2026 and each fiscal quarter thereafter.

•The Company is also required to maintain a minimum consolidated liquidity of (i) $50,000 as of the last day of each month, commencing as of October 31, 2024 and (ii) $100,000 as of the last day of any fiscal quarter,

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commencing as of December 31, 2024. The Company was in compliance with these covenants as of December 31, 2024.

The Revolving Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default.

The Company incurred $5,398 in origination, structuring and other fees, associated with entry into the Revolving Facility, which includes additional fees to expand the facility in 2022. During the years ended December 31, 2024 and 2023, the Company incurred an additional $32,410 and $9,431, respectively, in fees in relation to the amendments. Each amendment has been accounted for as a modification, and these costs have been capitalized within Other non-current assets on the Consolidated Balance Sheets. As of December 31, 2024 and 2023, total remaining unamortized deferred financing costs for the Revolving Facility was $38,190 and $11,923, respectively.

Letter of Credit Facility

In July 2021, the Company entered into an uncommitted letter of credit and reimbursement agreement (the "Letter of Credit Agreement") with a bank for the issuance of letters of credit for an aggregate amount of up to $75,000 (the“Letter of Credit Facility”). Through December 31, 2023, the Letter of Credit Facility was amended multiple times to increase the availability to $350,000. As at December 31, 2024, the Letter of Credit Facility had a limit of $315,000, and outstanding letters of credit have an interest rate of 3.35%. The Company had an unutilized Letter of Credit Facility balance of $69,000 as at December 31, 2024.

The Letter of Credit Agreement contains usual and customary representations and warranties, usual and customary affirmative and negative covenants and events of default. The Company is required to comply with the financial covenants applicable to the Revolving Facility.

Term Loan B Credit Agreement

On August 3, 2023, the Company entered into a credit agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) to the Company in an aggregate principal amount of $400,000. The Bridge Term Loans were initially set to mature on August 1, 2024 and were payable in full on the maturity date. The Bridge Term Loans bore interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Bridge Term Loan Agreement) plus 3.50%.

On October 30, 2023, the Company entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to the Company in an aggregate principal amount of $856,000 ("Term Loan B"). Borrowings were issued at a discount, and the Company received proceeds of $787,520. The proceeds from the Term Loan B issuance were used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature on the earliest of (i) October 30, 2028 if the 2026 Notes are refinanced in full prior to their maturity and (ii) July 31, 2026, if any of the 2026 Notes remain outstanding as of such date. Quarterly principal payments of approximately $2,140 are required beginning March 2024.

The obligations under the Term Loan B are guaranteed by certain of the Company's subsidiaries, including those that own the Company's FLNG1 Project and Altamira Onshore Project (defined below). The Term Loan B is secured by substantially the same collateral as the first lien obligations under the 2026 Notes, the Revolving Facility, and, in addition, is secured by assets compromising the Company's FLNG1 Project.

The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. The Company may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. The Company is required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, the Company will be required to prepay the Term Loan B with the Company’s Excess Cash Flow (as defined in the Term Loan B Agreement).

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In connection with the execution of the Bridge Term Loan Agreement and the Term Loan B Agreement, the Company incurred $17,719 in origination, structuring and other fees. The repayment of the Bridge Term Loans with borrowings under the Term Loan B Agreement was treated as a modification, and fees attributable to lenders that participated in the Bridge Term Loans will be amortized over the life of the Term Loan B Agreement; additional third-party fees associated with such lenders of $1,578 were recognized as expense in Transaction and integration costs. Additional fees for new lenders participating in the Term Loan B were recognized as a reduction of the principal balance on the Consolidated Balance Sheets. As of December 31, 2024 and 2023, total remaining unamortized deferred financing costs, including the unamortized original issue discount, for the Term Loan B were $71,087 and $84,580, respectively.

Term Loan A Credit Agreement

In July 2024, the Company entered into a credit agreement ("Term Loan A Credit Agreement") for a senior secured, multiple draw term loan facility in an aggregate principal amount of up to $700,000 ("Term Loan A"). Proceeds will be used to pay costs of the construction and development of the Company's onshore FLNG project in Altamira (the “Altamira Onshore Project”). During the year ended December 31, 2024, the Company drew $350,000 on the Term Loan A. The remaining commitments for subsequent funding expire on the earliest of June 30, 2026, the date of completion of the Onshore Altamira Project (the “Completion Date”) and the date that the commitments are reduced to zero or terminated.

The obligations under the Term Loan A Credit Agreement are guaranteed, jointly and severally, on a senior secured basis by each subsidiary that is a guarantor under the 2026 Notes, 2029 Notes, the Company’s Revolving Facility, the Company’s letter of credit facility (the “Letter of Credit Facility”) and the Company’s Term Loan B, other than the guarantors comprising the FLNG1 Project (who guarantee the Revolving Facility, the Letter of Credit Facility, and the Term Loan B). The obligations under the Term Loan A Credit Agreement are secured by substantially the same collateral as the collateral securing such facilities, with the exception of the collateral comprising the FLNG1 Project (which secures the Revolving Facility, the Letter of Credit Facility, and the Term Loan B). Additionally, the Term Loan A is guaranteed by the entities, and secured by the assets, comprising the Onshore Altamira Project. An equal priority intercreditor agreement governs the treatment of the collateral.

The Term Loan A will mature in July 2027 and is payable in full on the maturity date. In the event that the Company’s existing 2026 Notes are not refinanced or repaid at least 60 days prior to maturity, amounts outstanding under the Term Loan A will become due and payable on such date. The Company may prepay the Term Loan A at its option without premium or penalty at any time subject to customary break funding costs. The Company is required to prepay the Term Loan A with the net proceeds of certain asset sales, condemnations, debt and convertible securities issuances, and extraordinary receipts related to the Onshore Altamira Project. Additionally, commencing with the first fiscal quarter after the Completion Date, the Company will be required to prepay the Term Loan A with the Onshore Altamira Project’s Excess Cash Flow (as defined in the Term Loan A Credit Agreement).

The Term Loan A 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. The Company must also comply with certain financial covenants consistent with those under the Revolving Facility, including Debt to EBITDA Ratio and minimum consolidated liquidity.

In connection with the issuance of the Term Loan A, the Company incurred $39,227 in origination, structuring and other fees, which was capitalized in Other non-current assets on the Consolidated Balance Sheet as the Term Loan A is a delayed draw term loan. During the year ended December 31, 2024, $16,142 of fees were reclassified as a reduction of the principal balance of the Term Loan A on the Consolidated Balance Sheets as each draw was made. In addition, the Company recorded a debt discount of $8,830 as a result of an embedded derivative (Note 9). As of December 31, 2024, total remaining unamortized deferred financing costs and debt discount reducing the principal balance was $28,426.

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Short-term Borrowings

The Company has an LNG cargo financing arrangement where it may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby the Company sells to the financial institution an LNG cargo and concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of December 31, 2024, the Company had $179,890 due under repurchase arrangements with a weighted average interest rate of 8.87%. As of December 31, 2023, the Company had $182,270 due under repurchase arrangements with a weighted average interest rate of 9.68%.

Vessel Financing Obligation

In connection with of the Energos Formation Transaction (see discussion in Note 6), the Company entered into long-term time charter agreements for certain vessels for periods of up to 20 years. Vessels chartered to the Company at the time of closing were classified as finance leases. Additionally, the Company's charter of certain other vessels will commence only upon the expiration of the vessel's existing third-party charters. These forward starting charters prevented the recognition of a sale of the vessels to Energos. As such, the Company accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation for consideration received.

The Company continues to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, the Company recognizes revenue and operating expenses related to vessels under charter to third parties. Revenue recognized from these third-party charters form a portion of the debt service for the financing obligation; at inception of the arrangement, the effective interest rate on this financing obligation was approximately 15.9% and includes the cash flows that Energos receives from these third-party charters. Charter payments due in 2025 include $57,762 that will be treated as a payment of principal, and this amount is included within the current portion of long-term debt.

In connection with closing of the Energos Formation Transaction, the Company incurred $10,010 in origination, structuring and other fees, of which $2,995 was allocated to the sale of the Nanook and recognized as Other expense (income), net in the Consolidated Statements of Operations and Comprehensive (Loss) Income. Financing costs of $7,015 were allocated and deferred as a reduction of the principal balance of the financing obligation on the Consolidated Balance Sheets. As of December 31, 2024 and 2023, the remaining unamortized deferred financing costs for the Vessel Financing Obligation was $6,141 and $6,490, respectively.

Tugboat Financing

In December 2023, the Company sold and leased back four tugboat vessels for 15 years receiving proceeds of $46,728. ("Tugboat Financing"). The leasebacks of the tugboat vessels were classified as finance leases, and as such, the Company accounted for the Tugboat Financing as a failed sale-leaseback and has recorded a financing obligation for consideration received. The effective interest rate on this financing obligation is approximately 16.92%.

PortoCem Financings

As part of the PortoCem Acquisition, the Company assumed a term loan in the aggregate principal amount of R$141,445 million ($28,093 based on the exchange rate 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.

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day interbank deposit futures rate in Brazil plus 4.25%, and no principal payments were required until maturity in October 2025.

In November 2024, PortoCem issued R$4.5 billion ($726,750 based on exchange rates in effect at December 31, 2024) of debentures to BNDES ("PortoCem Debentures"). Borrowings bear interest at 9.15%. No principal or interest payments are due until September 2027; at that point, PortoCem will begin to make semi-annual payments until maturity in September 2040. Proceeds received were utilized to repay the PortoCem Bridge Loan, and the remaining proceeds are restricted to fund the construction of the PortoCem Power Plant.

The Company incurred $11,663 in origination, structuring and other fees in connection with the entry into the PortoCem Credit Note and the PortoCem Bridge Loan. The repayment of the PortoCem Bridge Loan was treated as an extinguishment, and the Company recognized $25,010 of repayment penalty and unamortized deferred financing fees as loss on extinguishment of debt in the Consolidated Statements of Operations and Comprehensive (Loss) Income at the time of repayment. The Company incurred $6,301 of new third party fees in conjunction with the repayment of the PortoCem Bridge Loan and issuance of the PortoCem Debentures. As of December 31, 2024, total remaining unamortized deferred financing costs for the PortoCem Debentures was $6,301.

Barcarena Financings

In October 2023, certain of the Company's Brazilian subsidiaries entered into two long-term financing arrangements, fully funding the construction of the Company's power plant located in Pará, Brazil (the "Barcarena Power Plant"). The parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures") and issued $180 million of the Barcarena Debentures prior to December 31, 2023. The remaining series may be issued upon the achievement of certain conditions precedent. Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12.0%, increasing 1.25% each year after the third anniversary of issuance. The Company is able to prepay the Barcarena Debentures, subject to certain make-whole penalties, and the Company is required to utilize certain excess cash flows from the Company's Brazilian operations to prepay principal.

The Barcarena Debentures are convertible into shares of one of the Company's indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion.

The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own the Barcarena Facility and the Santa Catarina Facility. NFE has also provided a parent company guarantee that will be released once the Barcarena Facility commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions.

The Company incurred $5,061 of structuring and other fees, and such fees were deferred as a reduction to the principal balance of the Barcarena Debentures. As of December 31, 2024 and 2023, the remaining unamortized deferred financing costs for the Barcarena Debentures were $3,085 and $4,975, respectively.

The owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). The Company is able to borrow up to $355,566 under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"). The Company borrowed $344,735 under the BNDES Credit Agreement in 2024. Each tranche bears a different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045. Interest payments prior to April 2026 are made through an increase in the outstanding principal amount and are due quarterly thereafter.

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covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions.

South Power 2029 Bonds

In January 2022, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into an agreement for the issuance of up to $285,000 secured bonds (“South Power 2029 Bonds”). The South Power 2029 Bonds are secured by, amongst other things, the Company’s combined heat and power plant in Clarendon, Jamaica (“CHP Plant”), and NFE has provided a guarantee of the obligations under the South Power 2029 Bonds. As of both December 31, 2024 and 2023, South Power had $221,824 of South Power 2029 Bonds issued and outstanding.

The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and shall be partially repaid in quarterly installments beginning in August 2025 with the final repayment date in May 2029. Interest payments on outstanding principal balances are due quarterly.

South Power is required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provide for customary events of default, prepayment and cure provisions. The Company was in compliance with all covenants as of December 31, 2024 and 2023.

As of December 31, 2024 and 2023, the remaining unamortized deferred financing costs for the South Power 2029 Bonds was $3,953 and $4,832, respectively.

Turbine Financing

In May 2024, the Company executed a loan agreement with a lender to borrow $148,500 under a promissory note secured by certain turbines owned by a wholly-owned subsidiary of the Company (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. The Company was required to pay a deposit of approximately $5,963 that will be held by the lender throughout the term of the borrowing which was recorded in Other non-current assets, net on the Consolidated Balance Sheets.

Proceeds received were net of upfront fees due to the lender, and through December 31, 2024 the Company has incurred $2,136 in origination, structuring and other fees, associated with entry into the Turbine Financing. As of December 31, 2024, total remaining unamortized deferred financing costs for the Turbine Financing was $1,753.

EB-5 Loan Agreement

On July 21, 2023, the Company 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 $100,000, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE's green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the year ended December 31,

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2023, $62,928 was funded under the EB-5 Loan Agreement, and the remaining availability of $37,072 was funded during the year ended December 31, 2024.

The Company has incurred $1,728 in origination, structuring and other fees associated with entry into the EB-5 Loan Agreement. As of December 31, 2024 and 2023, the total remaining unamortized deferred financing costs for the EB-5 Loan Agreement was $1,353 and $1,314, respectively.

Equipment Notes

In June 2023, the Company executed a Master Loan and Security Agreement with a lender to borrow up to $200,000 under promissory notes secured by certain turbines acquired in the first quarter of 2023 to support our grid stabilization project in Puerto Rico (the “Equipment Notes”). During 2023, the Company borrowed the full capacity bearing interest at approximately 7.68%, and the principal was partially repayable in monthly installments over the 36-month term of the loan with the balance due upon maturity in July 2026.

In conjunction with the execution of the APA to sell certain turbines to PREPA in March 2024 (Note 5), the Company repaid the Equipment Notes in full, releasing any liens held on the turbines prior to their sale. The balance outstanding as of the repayment date was $188,431, and the Company incurred a prepayment premium of 3%. The prepayment premium and any unamortized financing costs of $7,879 were recognized as Loss on extinguishment of debt, net in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

Interest Expense

Interest and related amortization of debt issuance costs, premiums and discounts recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the years ended December 31, 2024, 2023 and 2022 consisted of the following:


	Year Ended December 31,
	2024		2023		2022
Interest per contractual rates	$	561,477	$	339,631	$	227,960
Interest expense on Vessel Financing Obligation	192,107		211,745		91,405
Amortization of debt issuance costs, premiums and discounts	60,208		18,569		11,098
Interest expense incurred on finance lease obligations	981		3,706		852
Total interest costs	$	814,773	$	573,651	$	331,315
Capitalized interest	486,396		295,809		94,454
Total interest expense	$	328,377	$	277,842	$	236,861

Interest expense on the Vessel Financing Obligations includes non-cash expense of $120,962, $169,641, and $84,517 for the years ended December 31, 2024, 2023, and 2022, respectively, related to payments received by Energos from third party charterers.

21. Other Long-Term Liabilities

As of December 31, 2024 and 2023, Other long-term liabilities consisted of the following:

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	December 31, 2024		December 31, 2023
Guarantee liability	$	115,359	$	—
Derivative liabilities	24,364		18,383
Contract liability (Note 7)	11,750		31,698
Other	14,885		5,546
Total other long-term liabilities	$	166,358	$	55,627

In the fourth quarter of 2024, the Company novated an LNG supply contact to a customer (Note 7). In conjunction with this novation, the Company agreed to guarantee the performance of the LNG supplier, and the fair value of the guarantee of $115,539 was recognized. In exchange for this guarantee, the customer will make payments to the Company between the third quarter of 2026 through the first quarter of 2028 totaling $126,668 (Note 17). The value of the guarantee will be recognized as Contract novation income in the Consolidated Statements of Operations and Comprehensive (Loss) Income as these installment payments become due.

22. Income Taxes

The components of the Company’s income (loss) before income taxes for the years ended December 31, 2024, 2023 and 2022 were as follows:


	Year Ended December 31,
	2024		2023		2022
United States	$	(161,471)	$	287,768	$	551,500
Foreign	(11,407)		376,621		(490,153)
Income before taxes	$	(172,878)	$	664,389	$	61,347

Income tax expense is comprised of the following for the years ended December 31, 2024, 2023 and 2022:


	Year Ended December 31,
	2024		2023		2022
Current:
Domestic	$	36,175	$	47,198	$	37,831
Foreign	27,868		53,377		118,266
Total current tax expense	64,043		100,575		156,097
Deferred:
Domestic	(11,391)		4,030		5,794
Foreign	16,857		10,908		(285,330)
Total deferred tax (benefit) expenses	5,466		14,938		(279,536)
Total provision for (benefit from) income taxes	$	69,509	$	115,513	$	(123,439)

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Effective Tax Rate

A reconciliation of the U.S. federal statutory income tax rate to the Company’s effective tax rate is as follows:


	Year Ended December 31,
	2024		2023		2022
Income tax at the statutory rate	21.0	%	21.0	%	21.0	%
Foreign tax rate differential	71.1		(12.1)		(25.5)
US taxation on foreign earnings	(7.5)		0.1		25.5
Impact from foreign operations	12.9		0.4		(10.7)
Change in valuation allowance	(155.8)		8.2		(22.9)
Income attributable to non-controlling interest	—		—		1.3
Effects of share-based compensation	(3.0)		0.3		(39.8)
Withholding taxes	(0.2)		0.6		12.6
Income tax credits	9.4		(4.8)		(0.3)

Sergipe Sale	—		—		(165.4)
Outside basis differences	—		0.1		(3.2)
Changes in deferred taxes and payable	14.0		—		—
Other	(2.1)		3.6		6.2
Effective income tax rate	(40.2	%)	17.4	%	(201.2	%)

The Company has certain operations in jurisdictions that are not subject to income taxes or are subject to preferential tax rates. The effect of these earnings taxed at zero percent, as well as the impact of such preferential tax rates, are included in the foreign rate differential. The Organization for Economic Cooperation and Development is coordinating negotiations among more than 140 countries with the goal of achieving consensus around substantial changes to international tax policies, including the implementation of a minimum global effective tax rate of 15%. As of December 31, 2024, various countries have implemented the legislation, however, the legislation has not resulted in a material change to the income tax provision for the year ended December 31, 2024. As additional jurisdictions enact such legislation, the effective tax rate and cash tax payments could increase in future years.

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The tax effect of each type of temporary difference and carryforward that give rise to a significant deferred tax asset or liability as of December 31, 2024 and 2023 are as follows:


	Year Ended December 31,
	2024		2023
Deferred tax assets:

Accrued interest	$	49,870	$	37,735
IRC Section 163(j) interest carryforward	27,333		758
Federal and state net operating loss carryforward	658		2,063
Foreign net operating loss carryforward	256,863		123,386
Debt	362,942		289,820
Lease liability	126,743		106,293
Goodwill	43,004		47,043
Other	77,412		24,214
Total deferred tax assets	944,825		631,312
Valuation allowance	(450,072)		(188,036)
Deferred tax assets, net of valuation allowance	494,753		443,276

Deferred tax liabilities:
Property and equipment	(360,340)		(343,247)
Right-of-use assets	(126,764)		(107,919)


Intangibles	(46,077)		—
Deferred income	(132)		(20,714)
Capitalized costs	(20,542)		—
Other	(11,398)		(5,933)
Total deferred tax liabilities	$	(565,253)	$	(477,813)
Net deferred tax liabilities	$	(70,500)	$	(34,537)

Tax Attributes

United States

As of December 31, 2024, NFE has approximately $2,584 of federal and $2,927 of state net operating loss carry forwards. The federal and state net operating losses are generally allowed to be carried forward indefinitely and can offset up to 80 percent of future taxable income.

Under the provisions of Internal Revenue Code Section 382, certain substantial changes in the Company’s ownership may result in a limitation on the amount of U.S. net operating loss carryforwards that can be utilized annually to offset future taxable income and taxes payable. The Company’s net operating loss carryforwards are subject to an annual limitation of $5,431 under Section 382 of the Internal Revenue Code.

Foreign Jurisdictions

The Company’s foreign subsidiaries file income tax returns in certain foreign jurisdictions. As of December 31, 2024, the Company’s foreign subsidiaries have approximately $938,763 of net operating loss carry forwards, of which $254,294 will expire, if unused between 2028 and 2041, and the remaining $684,469 are allowed to be carried forward indefinitely.

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Valuation Allowances

The following table summarizes the changes in the Company’s valuation allowance on deferred tax assets for the years ended December 31, 2024 and 2023:


	Year Ended December 31,
	2024		2023
Balance at the beginning of the period	$	188,036	$	130,649
Change in valuation allowance	262,036		57,387
Balance at the end of the period	$	450,072	$	188,036

The change in valuation allowance was mainly due to increase in deferred tax asset related to debt extinguishment in the U.S. and increase in net operating losses in foreign jurisdictions for the year ended December 31, 2024.

NFE recorded a valuation allowance against its US federal and state deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized. The Company concluded, based on the weight of all available positive and negative evidence, those deferred tax assets are not more likely than not to be realized and accordingly, a valuation allowance has been recorded on this deferred tax asset for the amount not supported by reversing taxable temporary differences.

The Company recorded a valuation allowance against certain foreign deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized, generally based on cumulative losses in certain development stage jurisdictions.

Uncertain Taxes

The following table summarizes the changes in the Company’s unrecognized tax benefits for the years ended December 31, 2024 and 2023:


	Year Ended December 31,
	2024		2023
Balance at the beginning of the period	$	—	$	—
Recognized in the income tax provision	—		—

Balance at the end of the period	$	—	$	—

Income Tax Examinations

The Company and its subsidiaries file income tax returns in the U.S. federal and various state and local jurisdictions, as well as various foreign jurisdictions. The Company filed its first corporate U.S. federal and state income tax returns for the period ended December 31, 2019. The U.S. Federal and state income tax returns filed for tax years 2021, 2022 and 2023 are open for examination. The Company is generally open to tax examinations in other foreign jurisdictions for a period of four to six years from the filing of the income tax return.

Undistributed Earnings

The Company has not recorded a deferred tax liability for undistributed earnings for any controlled foreign corporation as of December 31, 2024. The Company has unremitted earnings in certain jurisdictions where distributions can be made at no net tax cost. From time to time, the Company may remit these earnings. The Company has the ability and intent to indefinitely reinvest any earnings that cannot be remitted at no net tax cost. It is not practicable to estimate the amount of any additional taxes which may be payable on these undistributed earnings.

Preferential Tax Rates

The Company has subsidiaries incorporated in Bermuda. Under current Bermuda law, the Company is not required to pay taxes in Bermuda on either income or capital gains. The Company has received an undertaking from the Bermuda

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government that, in the event of income or capital gain taxes being imposed, it will be exempted from such taxes until 2035. On December 27, 2023, Bermuda enacted the Bermuda Corporate Income Tax Act 2023, which institutes a corporate income tax rate of 15% effective for tax years beginning January 1, 2025. As a result, such tax exemptions will not be valid beyond such subsidiaries' taxable year ending December 31, 2024, the impact of which has been included in the tax provision and was not material.

The Company’s Puerto Rican operations received tax decrees from the Puerto Rico government that affords the Company a 4% tax rate on qualifying income. The effect of the earnings taxed at a 4% foreign tax rate is included in the foreign rate differential line in the Company’s effective tax rate. For the years ended December 31, 2024 and 2023, the income tax benefits attributable to the tax decrees, before taking into consideration the impact on U.S. taxation and the associated U.S. foreign tax credits, are estimated to be approximately $142,776 ($(0.65) per share of issued and outstanding Class A common stock on a diluted basis) and $164,668 ($(0.80) per share of issued and outstanding Class A common stock on a diluted basis), respectively.

23. Commitments and contingencies

The Company is subject to certain legal and regulatory proceedings, claims and disputes that arise in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

24. Earnings per share


	Year Ended December 31,
	2024		2023		2022
Basic
Numerator:
Net (loss) income	$	(242,387)	$	548,876	$	184,786
Net (loss) income attributable to non-controlling interests	(6,652)		(994)		9,693
Convertible preferred stock dividend	(3,462)		—		—
Deemed dividend from the preferred stock exchange	(17,605)		—		—
Net (loss) income attributable to Class A common stock	$	(270,106)	$	547,882	$	194,479

Denominator:
Weighted-average shares - basic	217,578,487		205,942,837		209,501,298
Net (loss) income per share - basic	$	(1.24)	$	2.66	$	0.93

Diluted
Numerator:
Net (loss) income	$	(242,387)	$	548,876	$	184,786
Net (loss) income attributable to non-controlling interests	(6,652)		(994)		9,693
Convertible preferred stock dividend	(3,462)		—		—
Deemed dividend from the preferred stock exchange	(17,605)		—		—
Adjustments attributable to dilutive securities	(2,418)		(736)		—
Net (loss) income attributable to Class A common stock	$	(272,524)	$	547,146	$	194,479

Denominator:
Weighted-average shares - diluted	218,622,419		206,481,977		209,854,413
Net (loss) income per share - diluted	$	(1.25)	$	2.65	$	0.93

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The following table presents potentially dilutive securities excluded from the computation of diluted net (loss) income per share for the years ended December 31, 2024, 2023 and 2022 because its effects would have been anti-dilutive.


	Year Ended December 31,
	2024	2023	2022
Unvested RSUs	1,579,802	—	—
Series B convertible preferred stock(1)	81,746	—	—
Equity agreement shares(2)	—	—	458,696

(1) Represents the number of unconverted Series B convertible preferred shares as of December 31, 2024. In December 2024, the Company received an irrevocable conversion notice for 15,000 shares. Refer to Note 4 for terms of conversion features.

(2) Represents Class A common stock that would be issued in relation to an agreement to issue shares executed in conjunction with a prior year asset acquisition.

During the year ended December 31, 2024, the Company paid dividends on the Series A Convertible Preferred Stock of $2,493. After the exchange of the Series A Convertible Preferred Shares with the Series B Convertible Preferred Shares in October 2024, the Company paid a dividend of $969 during the fourth quarter of 2024 (Refer to Note 4).

25. Stockholders' equity

Equity issuance

On October 1, 2024, the Company entered into an Underwriting Agreement with several underwriters to issue and sell 46,349,942 shares of the Company's Class A common stock, at a purchase price to the public of $8.63 per share, less underwriting discounts and commissions, in a registered public offering (the "Equity Offering"). The Company's Chief Executive Officer, Wesley R. Edens, agreed to purchase 5,793,742 shares at the public offering price per share and on the same terms as the other purchasers in the Equity Offering. The Equity Offering closed on October 2, 2024. The Company received net proceeds of approximately $386,583 after underwriters' discounts and commissions and the estimated offering expenses payable by the Company.

Dividends

The Company declared dividends of $0.10 per share totaling $61,517 during the year ended December 31, 2024, of which $41,010 have been paid. Under certain intercompany agreements entered into in conjunction with the Refinancing Transactions completed in the fourth quarter of 2024, New Fortress Energy Inc. is no longer permitted to pay dividends to shareholders. The Company paid quarterly dividends totaling $81,976 during the year ended December 31, 2023 representing $0.10 per Class A share. During 2022, the Company’s Board of Directors approved an update to its dividend policy and declared a dividend of $626,310, representing $3.00 per Class A share, which was paid in January 2023.

During each of the years ended December 31, 2024, 2023, and 2022, the Company paid dividends of $12,076 to holders of Golar LNG Partners LP's ("GMLP") 8.75% Series A Cumulative Redeemable Preferred Units (“GMLP Preferred Units”). As these equity interests have been issued by the Company’s consolidated subsidiaries, the value of the GMLP Preferred Units is recognized as non-controlling interest in the consolidated financial statements.

Upon the sale of the vessel Mazo (Refer to Note 12), one of the Company's non-wholly owned subsidiaries paid a dividend using proceeds from the sale. The dividend of $8,662 paid to the other shareholder in this subsidiary was recognized as a reduction to non-controlling interest during the first quarter of 2024.

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26. Share-based compensation

The Company has granted RSUs to select officers, employees and certain non-employees under the Incentive Plan. The fair value of RSUs on the grant date is estimated based on the closing price of the underlying shares on the grant date. The following table summarizes the RSU activity for the year ended December 31, 2024:


	Restricted Stock Units	Weighted-average grant date fair value per share
Non-vested RSUs as of December 31, 2023	32,327	$	27.12
Granted	2,786,112	32.66
Vested	(91,362)	19.78
Forfeited	(1,147,275)	32.64
Non-vested RSUs as of December 31, 2024	1,579,802	$	32.60

The non-vested RSUs vest over periods from 10 months to approximately two years following the grant date. The weighted-average remaining vesting period of non-vested RSUs totaled 0.5 years as of December 31, 2024.

For the years ended December 31, 2024, 2023, and 2022, the Company recognized compensation costs associated with equity awards in the Consolidated Statements of Operations and Comprehensive (Loss) Income as follows:


	Year Ended December 31, 2024		Year Ended December 31, 2023		Year Ended December 31, 2022
Operations and maintenance	$	250	$	—	$	4
Selling, general and administrative	50,375		1,574		30,378
Total share-based compensation expense	$	50,625	$	1,574	$	30,382

In the second quarter of 2024, the Company granted an equity award to certain employees that will settle in shares of a subsidiary owning the Company's Brazilian operations. The grant date fair value of this award was $53,958, and the award contains a service condition that will vest in annual increments through March 31, 2027. Compensation expense of $11,537 for the year ended December 31, 2024 associated with this award is included in the table above.

In 2021 and 2022, the Company granted PSUs to certain employees and non-employees that contain a performance condition under the Incentive Plan. Vesting was determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that would vest can range from zero to a multiple of units granted. As of December 31, 2023, the Company determined that it was not probable that the performance condition required for the PSUs granted in 2022 to vest would be achieved, and as such, no compensation expense was recognized for this award. During the fourth quarter of 2022, the Company determined that the PSUs granted in 2021 would vest at a multiple of two, resulting in vesting of 681,204 PSUs. Compensation cost for the service period since the grant date of $27,705 was recognized in 2022, and this compensation expense is included in the table above.

During the year ended December 31, 2024, the Company recognized a reversal of cumulative compensation expense of $13,584 for forfeited RSU awards; no significant reversals of compensation cost were recorded in the years ended December 31, 2023 and 2022. The Company recognizes the income tax benefits resulting from vesting of RSUs in the period of vesting, to the extent the compensation expense has been recognized. As of December 31, 2024, unrecognized compensation costs from non-vested RSUs was $14,420, and unrecognized compensation costs for other equity awards that will settle in shares of a subsidiary owning the Company's Brazilian operations was $42,422.

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27. Related party transactions

Management services

Messrs. Edens, chief executive officer and chairman of the Board of Directors, and Nardone, member of the Board of Directors, are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, charges the Company for administrative and general expenses incurred pursuant to its Administrative Services Agreement (“Administrative Agreement”). The charges under the Administrative Agreement that are attributable to the Company totaled $6,822, $5,845 and $5,087 for the years ended December 31, 2024, 2023 and 2022, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the Consolidated Statements of Operations and Comprehensive (Loss) Income. As of December 31, 2024 and 2023, $6,755 and $5,691 were due to Fortress, respectively.

In addition to administrative services, Mr. Edens owns an aircraft that the Company charters from a third party operator for business purposes in the ordinary course of operations. The Company incurred, at aircraft operator rates, charter costs of $2,126, $2,784 and $3,714 for the years ended December 31, 2024, 2023 and 2022, respectively. As of December 31, 2024 and 2023, $1,146 and $1,095 was due to this affiliate, respectively.

Fortress affiliated entities

The Company provides certain administrative services to related parties including entities affiliated with Fortress. No costs are incurred for such administrative services by the Company as the Company is fully reimbursed for all costs incurred. The Company has subleased a portion of office space to affiliates of entities managed by Fortress, and for the years ended December 31, 2024, 2023 and 2022, rent and office related expenses of $1,080, $913 and $857 were incurred by these affiliates, respectively. As of December 31, 2024 and 2023, $2,637 and $1,547 were due from affiliates, respectively.

Additionally, an entity formerly affiliated with Fortress and currently owned by Messrs. Edens and Nardone provides certain administrative services to the Company, as well as providing office space under a month-to-month non-exclusive license agreement. The Company incurred rent and administrative expenses of approximately $912, $2,702 and $2,453 for the years ended December 31, 2024, 2023 and 2022, respectively. In May 2024, this affiliate assigned the office lease to the Company, and after this point, the Company no longer incurs rent expense with this affiliate. As of December 31, 2024 and 2023, $3,614 and $2,702 were due to Fortress affiliated entities, respectively.

Land leases

Prior to the sale of the Company's Miami Facility in the fourth quarter of 2024, the Company leased land from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $349, $505 and $506 during the years ended December 31, 2024, 2023 and 2022, respectively, which was included within Operations and maintenance in the Consolidated Statements of Operations and Comprehensive (Loss) Income. No amounts are due to FECI as of December 31, 2024. The Company has amounts due to FECI of $92 and had recorded a lease liability of $3,368 as of December 31, 2023.

In September 2023, the Company entered into a lease agreement to lease land from Jefferson Terminal South LLC, which is an indirect, majority-owned subsidiary of a public company which is managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $731 and $0 during the years ended December 31, 2024 and 2023, respectively, which was included within Operations and maintenance in the Consolidated Statements of Operations and Comprehensive (Loss) Income. As of December 31, 2024, the Company recorded a right-of-use asset of $3,530 and a lease liability of $4,474 on the Consolidated Balance Sheets. As of December 31, 2023, the Company recorded a right-of-use asset of $3,885 and a lease liability of $4,098 on the Consolidated Balance Sheets.

DevTech investment

In 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest was reflected as non-controlling interest in the Company’s consolidated financial statements. The Company recognized approximately $537, $424 and $408 in expense within Selling, general and administrative for the years ended December 31, 2024, 2023 and 2022, respectively. As of December 31, 2024 and 2023, $149 and $106 were due to DevTech, respectively.

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28. Customer concentrations

For the year ended December 31, 2024, revenue from three significant customers constituted 48% of total revenue; no other customers comprised more than 10% of our revenue. For the year ended December 31, 2023, revenue from two significant customers constituted 47% of the total revenue. For the year ended December 31, 2022, revenue from two significant customers constituted 42% of the total revenue. These customers’ revenues are included in the Company’s Terminals and Infrastructure segment.

During the years ended December 31, 2024, 2023 and 2022, revenue from external customers that were derived from customers located in the United States were $1,045,654, $1,060,678 and $246,628, respectively, and from customers outside of the United States were $1,319,206, $1,352,618, and $2,121,644, respectively. The Company attributes revenue from customers to the country in which the party to the applicable agreement has its principal place of business.

As of December 31, 2024 and 2023, long lived assets, which are all non-current assets excluding investment in equity securities, restricted cash, deferred tax assets, goodwill, intangible assets and assets held for sale located in the United States were $1,529,478 and $1,744,591, respectively, and long lived assets located outside of the United States were $8,655,996 and $6,938,199, respectively, primarily located in Brazil and the Caribbean.

29. Segments

As of December 31, 2024, the Company operates in two reportable segments: Terminals and Infrastructure and Ships:

•Terminals and Infrastructure includes the Company’s vertically integrated gas to power solutions, spanning 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. Vessels that are utilized in the Company’s terminal, logistics or sub-charter operations are included in this segment.

Terminals and Infrastructure Operating Margin included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% investment in CELSEPAR; the Company disposed of this investment in the fourth quarter of 2022.

Terminal and Infrastructure segment includes realized gains and losses from the settlement of derivative transactions entered into as economic hedges to reduce market risks associated with commodity prices.

•Ships includes vessels that are currently chartered to third parties under long-term arrangements and are part of the the Energos Formation Transaction; three vessels are currently included in this segment. The Company’s investment in Energos was also included in the Ships segment prior to the disposition of this investment in the first quarter of 2024. Ships Operating Margin also included the Company's effective share of revenue, expenses and operating margin attributable to ownership of the common units of Hilli LLC prior to the disposition of this investment in the first quarter of 2023.

The Company's CEO who is the CODM, uses Segment Operating Margin to evaluate the performance of the segments and allocate resources. Segment Operating Margin is defined as the segment’s revenue less cost of sales less operations and maintenance less vessel operating expenses, excluding unrealized gains or losses to financial instruments recognized at fair value. The CODM includes deferred earnings from contracted sales for which a prepayment was received in the current period in the segment measure.

The CODM considers Segment Operating Margin to be the appropriate metric to evaluate and compare the ongoing operating performance of the Company’s segments on a consistent basis across reporting periods as it eliminates the effect of items which management does not believe are indicative of each segment’s operating performance.

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The table below presents segment information for the years ended December 31, 2024, 2023 and 2022:


Year Ended December 31, 2024
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(5)		Consolidated
Statement of operations:
Total revenues	$	2,044,273	$	170,587	$	2,214,860	$	150,000	$	2,364,860

Less(1):
Cost of sales(2)(4)	1,064,667		—		1,064,667		—		1,064,667
Vessel operating expenses	—		33,372		33,372		—		33,372
Operations and maintenance	174,313		—		174,313		—		174,313
Deferred earnings from contracted sales(6)	150,000		—		150,000		(150,000)		—
Segment Operating Margin	$	955,293	$	137,215	$	1,092,508	$	—	$	1,092,508
Balance sheet:
Total assets	$	12,309,565	$	557,931	$	12,867,496	$	—	$	12,867,496
Other segmental financial information:
Capital expenditures(3)	$	2,274,435	$	—	$	2,274,435	$	—	$	2,274,435


Year Ended December 31, 2023
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(5)		Consolidated
Statement of operations:
Total revenues	$	2,141,085	$	293,605	$	2,434,690	$	(21,394)	$	2,413,296

Less(1):
Cost of sales(2)(4)	764,828		—		764,828		112,623		877,451
Vessel operating expenses	—		51,387		51,387		(5,948)		45,439
Operations and maintenance	166,785		—		166,785		—		166,785
Segment Operating Margin	$	1,209,472	$	242,218	$	1,451,690	$	(128,069)	$	1,323,621
Balance sheet:
Total assets	$	9,680,917	$	820,328	$	10,501,245	$	—	$	10,501,245
Other segmental financial information:
Capital expenditures(3)	$	3,461,659	$	7,568	$	3,469,227	$	—	$	3,469,227

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Year Ended December 31, 2022
(in thousands of $)	Terminals and Infrastructure		Ships		Total Segment		Consolidation and Other(5)		Consolidated
Statement of operations:
Total revenues	$	2,168,565	$	444,616	$	2,613,181	$	(244,909)	$	2,368,272

Less(1):
Cost of sales(2)(4)	1,142,374		—		1,142,374		(131,946)		1,010,428
Vessel operating expenses	—		90,544		90,544		(27,026)		63,518
Operations and maintenance	129,970		—		129,970		(24,170)		105,800
Segment Operating Margin	$	896,221	$	354,072	$	1,250,293	$	(61,767)	$	1,188,526
Balance sheet:
Total assets	$	5,913,775	$	1,791,307	$	7,705,082	$	—	$	7,705,082
Other segmental financial information:
Capital expenditures(3)	$	1,482,871	$	27,127	$	1,509,998	$	—	$	1,509,998

(1)The significant expense categories and amounts align with the segment-level information that is regularly provided to the CODM.

(2)Cost of sales in the Company’s segment measure only includes realized gains and losses on derivative transactions that are an economic hedge of commodity purchases and sales, and a realized gain of $139,089 for the year ended December 31, 2023 was recognized as a reduction to Cost of sales in the segment measure. No realized gains or losses were recognized for the years ended December 31, 2024 and 2022.

The Company recognized unrealized (losses) and earnings of ($106,393) and $106,103 on the mark-to-market value of derivative transactions for the years ended December 31, 2023 and 2022, respectively, and these losses reconcile Cost of sales in the segment measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

The Company has excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6,232 for the year ended December 31, 2023 reconcile Cost of sales in the segment measure to Cost of sales in the Consolidated Statements of Operations and Comprehensive (Loss) Income. The Company did not incur such costs in the years ended December 31, 2024 and 2022.

(3)Capital expenditures includes amounts capitalized to construction in progress and additions to property, plant and equipment during the period.

(4)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the Consolidated Statements of Operations and Comprehensive (Loss) Income.

(5)For the year ended December 31, 2024, Consolidation and Other adjusts for the inclusion of deferred earnings from contracted sales of $150,000 (Note 7) which were recognized during the third and fourth quarters of 2024.

In 2023 and 2022, the effective share of revenues, expenses and operating margin attributable to the Company's ownership of the common units of Hilli LLC and the Company's 50% ownership of CELSEPAR was included in the segment measure prior to the disposition of these investments. Unrealized mark-to-market gains or losses on derivative instruments and the exclusion of non-capitalizable contract acquisition costs were also removed.

(6)Deferred earnings from contracted sales represent forward sales transactions that were contracted in the second and third quarters of 2024 and prepayment for these sales was received. Revenue has been recognized in the Consolidated Statements of Operations and Comprehensive (Loss) Income during the third and fourth quarters of 2024.

Consolidated Segment Operating Margin is defined as net income, adjusted for selling, general and administrative expenses, transaction and integration costs, depreciation and amortization, asset impairment expense, loss on sale of assets,

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interest expense, other (income) expense, net, loss on extinguishment of debt, net, tax provision and income from equity method investments.

The following table reconciles Net income, the most comparable financial statement measure, to Consolidated Segment Operating Margin:


	Year Ended December 31,
(in thousands of $)	2024		2023		2022
Net income	$	(242,387)	$	548,876	$	184,786
Add:
Selling, general and administrative	285,520		205,104		236,051
Transaction and integration costs	12,279		6,946		21,796
Depreciation and amortization	162,014		187,324		142,640
Interest expense	328,377		277,842		236,861
Other expense (income), net	113,077		10,408		(48,044)
Loss (gain) on sale of assets, net	77,562		(29,378)		—
Tax provision (benefit)	69,509		115,513		(123,439)
Asset impairment expense	16,494		10,958		50,659
Loss on extinguishment of debt, net	270,063		—		14,997
Income (loss) from equity method investments	—		(9,972)		472,219
Consolidated Segment Operating Margin	$	1,092,508	$	1,323,621	$	1,188,526

30. Subsequent events

In February 2025, one of the Company's consolidated subsidiaries entered into an agreement to issue up to $350,000 aggregate principal amount of 15% Senior Secured Notes due 2029 (the “Brazil Financing Notes”) at a purchase price of 97.75% of par. The Brazil Financing Notes bear interest at a rate of 15.0% and mature on August 30, 2029; the principal is due in full on the maturity date. Interest is payable quarterly in arrears beginning on March 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 was used to repay the Barcarena Debentures in full.

In March 2025, the Company entered into an amendment to the Term Loan B Agreement. Pursuant to the amendment, certain lenders agreed to provide incremental term loans in an aggregate principal amount of up to $425,000. The incremental term loans are subject to the same terms as the initial Term Loan B, including interest rates and maturity date. Net proceeds will be used primarily to fund capital expenditures of the Altamira Onshore Project, and for other corporate expenses. In connection with the amendment, all unused term loan commitments under the Term Loan A Credit Agreement were terminated.

In March 2025, the Company entered into a Backstop Agreement (the "Backstop Agreement") with a lender, pursuant to which the Company may, at its sole option, issue and sell to this lender (subject to the satisfaction of certain conditions) senior debt securities up to an aggregate principal amount sufficient to generate gross proceeds of $100,000 with a term of at least three years from the closing date. Proceeds received would be used to satisfy the repayment of the outstanding borrowings under the Revolving Facility required by the reduction of commitments by September 30, 2025 (Note 20). The Backstop Agreement would be terminated in the event that the Company completes the sale of assets or receives proceeds associated with a contract termination fee sufficient to satisfy such required repayment.

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Schedule II


Description	Balance at Beginning of Year		Additions(1)		Deductions		Balance at End of Year

Year ended December 31, 2024

Allowance for expected credit losses	$	1,484	$	13,157	$	(172)	$	14,469

Year ended December 31, 2023

Allowance for expected credit losses	1,526		—		(42)		1,484

Year ended December 31, 2022

Allowance for expected credit losses	2,159		835		(1,468)		1,526

Notes:

(1)Amount expensed is included within Selling, general and administrative.

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