New Fortress Energy Inc. (NFE) FY 2022 MD&A

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, 2021 and 2020 can be found in our Annual Report on Form 10‑K for the year ended December 31, 2021 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 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 (i) prior to the completion of Mergers (defined below), New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries, and (ii) after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP 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 Very-Low-Carbon Future.”

Our chief operating decision maker makes resource allocation decisions and assesses performance on the basis of two operating segments, Terminals and Infrastructure and Ships.

Our Terminals and Infrastructure segment includes the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third-party suppliers and from our own liquefaction facility in Miami, Florida. Starting in 2023, we expect to begin to source a portion of our LNG from our modular floating liquefaction facilities, which we refer to as "Fast LNG" or "FLNG." The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, as well as vessels utilized in our terminal or logistics operations. We centrally manage our LNG supply and the deployment of our vessels utilized in our terminal or logistics operations, which allows us to optimally manage our LNG supply and fleet.

Our Ships segment includes all vessels which are leased to customers under long-term or spot arrangements. The Company’s investments in Hilli LLC, owner and operator of the Hilli, and Energos (defined below) are also included in the Ships segment. Over time, we expect to utilize these vessels in our own terminal operations as charter agreements for these vessels expire.

Our Current Operations – Terminals and Infrastructure

Our management team has successfully employed our strategy to secure long-term contracts with significant customers, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica

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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”), a subsidiary of Federal Electricity Commission (Comisión Federal de Electricidad), 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 61,000 MMBtu from 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 (the “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 (the “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 and other industrial end-user customers in Puerto Rico.

La Paz Facility

In July 2021, we began commercial operations at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). The La Paz Facility is expected to supply approximately 22,300 MMBtu from LNG per day to our 100MW of power supplied by gas-fired modular power units (the “La Paz Power Plant”) following the start of operations. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu from LNG per day for up to 135MW of power.

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 and are in the process of finalizing long-form agreements to commemorate all binding terms. The gas sales and power plant sale agreements are subject to execution of the long-form final agreements and certain conditions precedent, and we expect to execute the long-form final agreements in the first quarter of 2023. We do not expect to recognize a loss on sale upon completion of this transaction.

Miami Facility

Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu from 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.

Our LNG Supply and Cargo Sales

NFE provides reliable, affordable and clean energy supplies to customers around the world that we plan to satisfy through the following sources: 1) our current contractual supply commitments; 2) additional LNG supply contracts

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expected to commence in 2026; 3) our Miami Facility; and 4) supply from our own Fast LNG production. We have secured commitments to purchase and receive physical delivery of LNG volumes for 100% of our expected committed volumes for each of our downstream terminals inclusive of our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and Santa Catarina Facility. Additionally, we have binding contracts for LNG volumes from two separate U.S. LNG facilities, each with a 20-year term, that are expected to commence in 2026 and 2027. Finally, we plan to commence our own Fast LNG production in 2023, when our first FLNG facility is expected to begin operation, and we plan to expand that capacity when additional units come online over the next two years.

The recent geopolitical events in Europe have substantially impacted the natural gas and LNG markets with unprecedented price increases and volatility. 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 from FLNG facilities expected to commence in 2023, we plan to further mitigate our exposure to variability in LNG prices. Due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated global LNG market. As FLNG facilities commence production, our long-term strategy is to sell substantially all cargos produced to customers on a long-term, take-or-pay basis through our downstream terminals.

Our Current Operations – Ships

Our Ships segment includes five FSRUs and five LNG carriers, which are leased to customers under long-term or spot arrangements and our investment in Hilli LLC, owner and operator of the Hilli. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. One LNG carrier and FSRU are currently utilized in our terminal operations, and the results of operations of these vessels are reflected in the Terminals and Infrastructure segment. In August 2022, we completed a financing transaction with an affiliate of Apollo Global Management, Inc. collateralized by our vessels. See “—Factors Impacting Comparability of Our Financial Results” for more details about this transaction; the results of operations from charters of vessels included in this transaction continue to be included in our Ships segment as well as our equity method investment in Energos (defined below).

Our Development Projects

Our projects currently under development include our development of a series of modular floating 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 in Puerto Sandino, Nicaragua (“Puerto Sandino Facility”); our LNG terminal (“Barcarena Facility”) and power plant (“Barcarena Power Plant”) located in Pará, Brazil; our LNG terminal located on the southern coast of Brazil ("Santa Catarina Terminal"); and our LNG terminal (“Ireland Facility”) and power plant in Ireland. 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 floating liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing offshore liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefication solutions. The “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 land-based alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

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Our initial Fast LNG units are being constructed at the Kiewit Offshore Services shipyard near Corpus Christi, Texas. The Kiewit facility specializes in the fabrication and integration of offshore projects. In partnership with Kiewit, we believe we have established an efficient and repeatable process to reduce cost and time to build incremental liquefaction capacity. We expect to deploy our first Fast LNG unit in 2023 and additional units in 2024.

We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below.

Altamira

In the fourth quarter of 2022, we finalized short-form agreements, which include conditions to effectiveness that have not been satisfied, with the Comisión Federal de Electricidad (“CFE”) to supply natural gas to two FLNG units located off the coast of Altamira, Tamaulipas, Mexico. These arrangements are subject to finalizing long-form definitive agreements and satisfying certain conditions precedent. Each 1.4 million tons per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. We expect to deploy our first FLNG unit to Altamira in 2023.

Louisiana

In addition, we 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

Also, in the fourth quarter of 2022, we finalized agreements, which include conditions to effectiveness that have not been satisfied, 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. If the agreements become effective, NFE would invest in the continued development of the Lakach field over a two-year period by completing seven offshore wells and to deploy a 1.4 MTPA Fast LNG unit to liquefy the majority of the produced natural gas. Remaining natural gas and associated condensate volumes would be utilized by Pemex in Mexico's onshore domestic market.

Puerto Sandino Facility

We are developing an offshore facility consisting of an FSRU and associated infrastructure, including mooring and offshore pipelines, in Puerto Sandino, Nicaragua. We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 MMBtu from LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. As part of our long-term partnership with the local utility, we are evaluating solutions to optimize power generation efficiency and allow for additional electrical capacity in a market that is underserved. We expect to complete this optimization in 2024.

Barcarena Facility

The Barcarena Facility consists of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility is capable of processing up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to supply gas to third-party industrial and power customers as well as the Barcarena Power Plant, a new 605MW combined cycle thermal power plant to be located in Pará, Brazil, which we own and which is supported by multiple 25-year power purchase agreements to supply electricity to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025. We substantially completed our Barcarena Facility in 2022 and expect to commence operations by the end of 2023. We expect to complete the Barcarena Power Plant and to commence operations in 2025.

We have financed the development of the Barcarena Power Plant pursuant to a financing agreement. See “—Long-Term Debt and Preferred Stock.”

Santa Catarina Facility

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The Santa Catarina Facility will be located on the southern coast of Brazil and will consist of an FSRU with a processing capacity of approximately 570,000 MMBtus per day and LNG storage capacity of up to 170,000 cubic meters. We are developing a 33-kilometer, 20-inch pipeline that will connect the Santa Catarina Facility to the existing inland Transportadora Brasileira Gasoduto Bolivia-Brasil S.A. (“TBG”) pipeline via an interconnection point in the municipality of Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day. We expect to complete our Santa Catarina Facility and commence operations in 2023.

Ireland Facility

We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. We are in the process of obtaining final planning permission from An Bord Pleanála (“ABP”) in Ireland. While the specific timing for receiving the required permits is unknown, we have undertaken pre-development work that will allow us to complete the terminal in approximately 9-15 months after receiving the required permits. We currently expect to begin operations in the first half of 2024.

Recent Developments

On February 6, 2023, we announced an agreement with Golar LNG Limited (“GLNG”) for the sale of our ownership stake in the Hilli Episeyo (the “Hilli”) in exchange for the return of approximately 4.1 million NFE shares and $100.0 million in cash (the "Hilli Exchange"). Pursuant to the transaction, we will no longer have any interest in the 2.4 MTPA floating liquefaction facility Hilli. This transaction is expected to close in the first quarter of 2023 and is subject to customary closing conditions.

Recent market prices of NFE shares and the terms of the Hilli Exchange implied that the fair value of the investment may be lower than the carrying value as of December 31, 2022, which triggered an assessment of the recoverability of the carrying amount of this investment. We estimated the fair value of the investment as of December 31, 2022 and concluded that the estimated fair value was below the carrying value and that this decline was other than temporary. As a result of this recoverability assessment, we recognized an OTTI of the investment in Hilli of $118,558 for the year ended December 31, 2022; this loss was recognized in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). The gain or loss recognized upon the closing of the Hilli Exchange will be determined based upon the share price at closing.

In February 2023, the Revolving Facility (defined below) was amended to increase the facility size by $301.7 million to $741.7 million. The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed. No changes were made to the maturity date or covenants. Also, in February 2023, our uncommitted letter of credit and reimbursement agreement was upsized to $325 million; no changes to interest rates or other terms were made as part of this amendment.

Other Matters

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. 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 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.

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Factors Impacting Comparability of Our Financial Results

Significant 2022 Transactions

We completed significant transactions in 2022 and 2021, including a significant sales and financing transaction collateralized by certain vessels as further described below, the sale of our investment in entities owning the Sergipe Power Plant (defined below) and our acquisitions of GMLP and Hygo, and these significant transactions impact the comparability of our historical financial results of operations.

Energos Formation Transaction

On August 15, 2022, the Company and an affiliate of certain funds or investment vehicles managed by affiliates of Apollo Global Management, Inc., AP Neptune Holdings Ltd. ("Purchaser"), created a joint venture and completed a sales and financing transaction resulting in cash proceeds of approximately $1.85 billion. This sales and financing transaction comprised (1) the formation of a joint venture doing business as Energos Infrastructure ("Energos"), (2) the sale for cash of eight vessels, along with these vessels' owning and operating entities to the Purchaser, (3) the contribution of acquired vessel-owning entities to Energos by the Purchaser and (4) the Company's contribution of three vessels, along with each vessel's' owning and operating entities, to Energos in exchange for equity in Energos (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, we own approximately a 20% equity interest in Energos, with the remaining interest owned by the Purchaser. We have accounted for the investment in Energos as an equity method investment.

In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for periods of up to 20 years in respect of ten of the eleven vessels, the terms of which will commence upon the expiration of each vessel's existing charter. These charters prevent the recognition of a sale of these ten vessels to Energos, and as such, proceeds associated with these ten vessels have been treated as failed sale leasebacks. These vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and we have recognized this failed sale leaseback financing as debt. Certain vessels included in the Energos Formation Transaction are currently chartered to third parties under operating leases. As we have not recognized the sale of these vessels and proceeds received under the Energos Formation Transaction are collateralized by the cash flows from these charters, revenue generated from these operating leases continues to be recognized as Vessel charter revenue; costs of operating the vessels is included in Vessel operating expenses over the terms of the third-party charters. Cash flows from these third-party charters are included as part of debt service for the sale leaseback financing debt, and we will recognize additional financing costs within Interest expense, net.

We have not entered into a charter agreement to leaseback the Nanook. The Nanook was previously accounted for as a finance lease and proceeds received have been allocated between financing of other vessels and the sale of the Nanook. After closing this transaction, we no longer recognize revenue from the sales-type lease of the Nanook to CELSE and the related operating services agreement.

Sergipe Sale

We acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) as part of the Hygo Merger (defined below); CELSEPAR owns 100% of the share capital of Centrais Elétricas de Sergipe S.A. (“CELSE”), the owner and operator of a 1.5GW power plant in Sergipe, Brazil (the "Sergipe Power Plant"). The Sergipe Power Plant was jointly owned and operated with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., and the Company accounted for this 50% investment using the equity method.

On May 31, 2022, one of our subsidiaries and certain Ebrasil sellers as owners of CELSEPAR (the “Sergipe Sellers”), Eneva S.A., as purchaser ("Eneva") and Eletricidade do Brasil S.A. -- Ebrasil, entered into a Share Purchase Agreement pursuant to which Eneva agreed to acquire all of the outstanding shares of (a) CELSEPAR and (b) Centrais Elétricas Barra dos Coqueiros S.A. ("CEBARRA"), which owns 1.7GW of expansion rights adjacent to the Sergipe Power Plant (the “Sergipe Sale”). The Sergipe Sale was completed on October 3, 2022, and Eneva paid the Sergipe Sellers R$6.8 billion (approximately $1.3 billion using the exchange rate as of the closing date). We also entered into a foreign currency forward associated to mitigate foreign currency risk to the expected proceeds from the transaction, and this foreign currency forward settled on October 3, 2022, resulting in a gain of $20.4 million.

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Since the Sergipe Sale in October 2022, we no longer include the results of our equity method investment in CELSEPAR in our financial statements. The results of operations of the Sergipe Power Plant were included in our Terminal and Infrastructure segment results, contributing segment operation margin of $95.6 million for the year ended December 31, 2022. Finally, we have recognized an other than temporary impairment on our investment in CELSEPAR of $369.2 million and an impairment loss on the assets held by CEBARRA of $50.7 million; as the Sergipe Sale closed in 2022, there will be no further impairment loss on this investment in future periods.

Hygo Merger and GMLP Merger

On April 15, 2021, we completed the acquisitions of Hygo (the "Hygo Merger") and GMLP (the "GMLP Merger," and collectively with the Hygo Merger, the “Mergers”) As a result of the Mergers, we acquired a 50% interest in the Sergipe Power Plant and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), the Barcarena Facility, Barcarena Power Plant, Santa Catarina Facility and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. We also acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli. The results of operations of the vessels acquired are included in our results of operations for the period after the acquisition date in 2021 and for a full year in 2022; the Nanook is only included in our results of operations in 2022 for the period prior to the Energos Formation Transaction.

Comparability to future periods

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:

•Our historical financial results do not reflect our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the year ended December 31, 2022. We anticipate the deployment of Fast LNG facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers.

•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, 2022 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We have placed a portion of our La Paz Facility into service, and our revenue and results of operations have begun to be impacted by operations in Mexico. We have executed short-form agreements to extend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur and are in the process of finalizing long-form agreements to commemorate all binding terms. We are also continuing to develop our Puerto Sandino Facility, and our current results do not include revenue and operating results from this project. Our current results also exclude other developments, including the Barcarena Facility, Santa Catarina Facility and Ireland Facility.

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Results of Operations – Three Months Ended December 31, 2022 compared to Three Months Ended September 30, 2022 and Year Ended December 31, 2022 compared to Year Ended December 31, 2021

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/(loss) from operations, net income/(loss), 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 to facilitate measuring and achieving optimal financial performance of our current operations overall. 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, 2022 and September 30, 2022, and for the year ended December 31, 2022 and December 31, 2021:

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(1)Prior to the completion of the Sergipe Sale, Terminals and Infrastructure included the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of CELSEPAR. The losses attributable to the investment of $0 and $44.6 million for the three months ended December 31, 2022 and September 30, 2022, respectively and $397.9 million and $17.9 million for the years ended December 31, 2022 and 2021, respectively, are reported in (Loss) income from equity method investments in the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market earnings and loss on derivative instruments of $96.4 million and $6.9 million for the three months ended December 31, 2022 and September 30, 2022, respectively and $106.1 million and $2.8 million for the years ended December 31, 2022 and 2021, respectively, reported in Cost of sales.

(2)Ships includes the Company’s effective share of revenues, expenses and operating margin attributable to the Company's 50% ownership of the Hilli Common Units. The loss and earnings attributable to the investment of $120.6 million and $12.8 million for the three months ended December 31, 2022 and September 30, 2022, respectively, and $77.1 million and $32.4 million for the years ended December 31, 2022 and 2021, respectively, are reported in (Loss)

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income from equity method investments in the consolidated statements of operations and comprehensive income (loss).

(3)Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments.

(4)Cost of sales is presented exclusive of costs included in Depreciation and amortization in the consolidated statements of operations and comprehensive income (loss).

(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

Total revenue

Total revenue for the Terminals and Infrastructure Segment decreased by $230.1 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. The decrease was primarily driven by decreased revenue from LNG cargo sales and decreases to the Henry Hub index that forms a portion of the pricing to invoice most of our downstream customers in this segment. Revenue from cargo sales was $231.1 million for the three months ended December 31, 2022 and $350.6 million for the three months ended September 30, 2022. The average Henry Hub index pricing used to invoice our downstream customers decreased by 24% for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022.

Total volumes delivered to downstream customers also contributed to the decrease in revenue for the three months ended December 31, 2022; volumes delivered for the three months ended December 31, 2022 were 11.0 TBtus as compared to 12.9 TBtus for the three months ended September 30, 2022. Volumes delivered decreased primarily due to maintenance at the San Juan Power Plant.

Total revenue for the Terminals and Infrastructure Segment increased by $802.4 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily driven by increased revenue from LNG cargo sales and increases to the Henry Hub index that forms a portion of the pricing to invoice most of our downstream customers in this segment. Revenue from cargos sales was $1,175.9 million for the year ended December 31, 2022 as compared to $462.7 million for the year ended December 31, 2021. The average Henry Hub index pricing used to invoice our downstream customers increased by 73% for the year ended December 31, 2022 as compared to the year ended December 31, 2021.

The significant increase in pricing was partially offset by decreases in total volumes delivered to downstream customers; for the year ended December 31, 2022 volumes delivered to downstream customers were 39.5 TBtus as

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compared to 41.8 TBtus for the year ended December 31, 2021. Volumes delivered decreased due to maintenance at the Montego Bay Facility and San Juan Power Plant.

After the completion of the Sergipe Sale, we no longer recognize our share of revenue from our ownership interest in CELSEPAR, and no revenue was recognized for three months ended December 31, 2022. Our share of revenue from our investment in CELSEPAR was $41.3 million for the three months ended September 30, 2022, which was primarily comprised of fixed capacity payments received under CELSE's PPAs. Our share of revenue from our investment in CELSEPAR was $148.3 million for the year ended December 31, 2022 as compared to $299.2 million for the year ended December 31, 2021, which represents our share of revenue for the period after the Mergers. Prior year revenue was higher due to revenue recognized from the emergency dispatch of the Sergipe Power Plant in the third quarter of 2021 due to poor hydrological conditions in Brazil.

Cost of sales

Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales.

Cost of sales decreased $170.0 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022.

•We recognized $97.8 million during the three months ended December 31, 2022 to acquire cargos sold to third parties, as compared to $185.7 million for the three months ended September 30, 2022. The weighted-average cost of LNG from cargo sales decreased from $18.26 per MMBtu for the three months ended September 30, 2022 to $10.52 per MMBtu for the three months ended December 31, 2022.

•Cost of LNG purchased from third parties for sale to our downstream customers decreased $33.3 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. The decrease was primarily attributable to a 15% decrease in volumes delivered compared to the three months ended September 30, 2022, and decreases in LNG cost. The weighted-average cost of LNG purchased from third parties for sale to our customers decreased from $12.17 per MMBtu for the three months ended September 30, 2022 to $10.95 per MMBtu for the three months ended December 31, 2022.

•During the three months ended December 31, 2022, we settled a commodity swap transaction to swap market pricing exposure for a portion of January 2023 deliveries (approximately 1.5 TBtus) for a fixed price of $61.87 per MMBtu, at a gain of $36.5 million.

Cost of sales increased by $353.3 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021.

•The increase in Cost of sales was primarily due to higher cost of LNG cargos NFE sold into the market. We recognized cost to acquire LNG cargos sold to third parties totaling $485.4 million during the year ended December 31, 2022 compared to $191.3 million for the year ended December 31, 2021.

•Cost of LNG purchased from third parties for sale to our terminal customers increased $141.5 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. While we delivered 6% less volumes to our terminal customers in the current period as compared to the prior year, our cost of LNG was significantly higher in the current period. The weighted-average cost of LNG purchased from third parties increased from $7.09 per MMBtu for the year ended December 31, 2021 to $10.84 per MMBtu for the year ended December 31, 2022.

•Vessel costs increased $53.0 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021 due to additional vessels used in our expanded operations.

•These increases were partially offset by a decrease in our share of cost of sales from our former investment in CELSEPAR from $175.8 million during the year ended December 31, 2021 to $28.6 million during the year ended December 31, 2022. As hydrology conditions have continued to improve in Brazil, the Sergipe Power Plant

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was not dispatched as regularly in 2022 and the investment in CELSEPAR was sold during the fourth quarter of 2022, reducing cost of sales from our share of our investment in CELSEPAR.

The weighted-average cost of our LNG inventory balance to be used in our operations as of December 31, 2022 and December 31, 2021 was $10.42 per MMBtu and $9.71 per MMBtu, respectively.

Vessel operating expenses

Vessel operating expenses include direct costs associated with operating a vessel, and these costs are typically included in the Ships segment. Once we begin to use a vessel in our terminal operations, the costs of the vessel begin to be included in the Terminals and Infrastructure segment. Vessel operating expenses were $3.4 million for the year ended December 31, 2021. We did not incur similar costs in this segment during the year ended December 31, 2022.

Operations and maintenance

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

Operations and maintenance decreased $4.6 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022, which was primarily attributable to the decrease in our share of Operations and maintenance from our former investment in CELSEPAR. After the completion of the Sergipe Sale, we no longer recognize our share of Operations and maintenance from our former ownership interest in CELSEPAR, and no Operations and maintenance costs were recognized for the three months ended December 31, 2022.

Operations and maintenance increased $37.5 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021.

•The increase for the year ended December 31, 2022 as compared to the year ended December 31, 2021 was primarily attributable to maintenance costs at our Montego Bay Facility and San Juan Power Plant, and higher logistics costs associated with our ISO container distribution system. Due to the reconfiguration and partial relocation of our assets at the Port of Montego Bay in 2022, we began to source LNG from our Miami Facility to service industrial end users in Jamaica, and we incurred additional costs to distribute LNG to customers via our ISO container distribution system. Maintenance costs and logistics costs increased by $10.2 million and $18.1 million, respectively.

•Additionally, Operations and maintenance increased $5.1 million due to the inclusion of our share of Operations and maintenance from our former investment in CELSEPAR from $19.1 million for the year ended December 31, 2021 to $24.2 million for the year ended December 31, 2022, which represents the costs for the period after the Merger. These costs are primarily related to the operation and services agreement for the Nanook, insurance costs and costs for connecting to the transmission system.

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Ships Segment

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. Prior to the completion of the Energos Formation Transaction, we also recognized revenue related to the interest portion of lease payments and the operating and service agreements in connection with the sales-type lease of the Nanook. We included the interest income earned under sales-type leases as revenue as amounts earned under chartering and operating service agreements represented our ongoing ordinary business operations.

At the completion of the Mergers, five of the FSRUs and two LNG carriers were on hire under long-term charter agreements, and one LNG carriers, the Grand, was operating in the spot market. In the third quarter of 2021, the Grand, began to be utilized in our terminal and logistics operations, and as such, the results of operations of the Grand are included in the Terminals and Infrastructure segment from the third quarter of 2021 onward. The Spirit and the Mazo continue to be in cold lay-up, and no vessel charter revenue was generated from these vessels.

Total revenue

Total revenue for the Ships segment was substantially consistent for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of vessels included in the transaction (except the Nanook), and as such, we continue to recognize revenue from the charter of these vessels to third parties. Revenues from the Ships segment remained substantially consistent as decreased revenue due to the sale of the Nanook was offset by additional sub-charter revenue.

Total revenue for the Ships segment increased $115.0 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. We completed the Mergers, including all of the vessels comprising the Ships segment, on April 15, 2021, and the increase in revenue is due to the inclusion of the Ships segment in our results of operations for a full year.

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. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter.

Vessel operating expenses decreased by $4.3 million for the three months ended December 31, 2022, compared to the three months ended September 30, 2022. The decrease is related to reduced operating costs and management fees due to the sale of the Nanook as a result of the Energos Formation Transaction.

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Vessel operating expenses increased $26.2 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. We completed the Mergers, including all of the vessels comprising the Ships segment, on April 15, 2021, and the increase in vessel operating expenses is due to the inclusion of the Ships segment in our results of operations for a full year.

Other operating results

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 associated with development activities for projects that are in initial stages and development is not yet probable.

Selling, general and administrative was substantially consistent for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022.

Selling, general and administrative increased $36.2 million for the year ended December 31, 2022, compared to the year ended December 31, 2021. The increase was primarily attributable to higher payroll and professional fees associated with the continued expansion of our operations.

Transaction and integration costs

For the three months ended December 31, 2022, we incurred $9.4 million of transaction and integration costs, as compared to $5.6 million for the three months ended September 30, 2022. For the both the three months ended December 31, 2022 and three months ended September 30, 2022, transaction and integration costs incurred were primarily associated with closing the Sergipe Sale. Additionally, during the third quarter of 2022, we incurred costs to close the Energos Formation Transaction. Certain costs could not be deferred as a reduction of the principal balance of the financing obligation incurred as a result of the Energos Formation Transaction, and these costs were recognized in the third quarter of 2022.

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For the year ended December 31, 2022, we incurred $21.8 million for transaction and integration costs, as compared to $44.7 million for the year ended December 31, 2021. In the current year, we have incurred transaction and integration costs primarily associated with the Sergipe Sale and the Energos Formation Transaction. For the year ended December 31, 2021, we incurred transaction and integration costs in connection with the Mergers, which consisted primarily of financial advisory, legal accounting and consulting costs. We have incurred such integration costs to a lesser extent in the current year as the integration of GMLP and Hygo has progressed since the acquisition date.

Depreciation and amortization

Depreciation and amortization was substantially consistent for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we continue to recognize depreciation expense for these vessels, resulting in consistent depreciation quarter over quarter.

Depreciation and amortization increased $44.3 million for the year ended December 31, 2022 as compared to the year ended December 31, 2021. The increase was primarily due to the following:

•Our results of operations include depreciation expense for the vessels acquired in the Mergers for a full year. We recognized $20.8 million of incremental depreciation expense for the acquired vessels during the year ended December 31, 2022.

•Amortization of the value recorded for favorable and unfavorable contracts of an additional $18.3 million for the year ended December 31, 2022.

Asset impairment expense

In conjunction with the Sergipe Sale, the assets of CEBARRA met the criteria to be represented as held for sale and stated at fair value. These assets were reviewed for impairment upon classification to held for sale, and we recognized an impairment loss of $50.7 million in Asset impairment expense during the year ended December 31, 2022 in the consolidated statements of operations and comprehensive income (loss).

Interest expense

Interest expense increased by $16.9 million for the three months ended December 31, 2022 as compared to the three months ended September 30, 2022. The increase was primarily due to the higher borrowing costs associated with financing obligations incurred as a result of the Energos Formation Transaction. Subsequent to the Energos Formation Transaction, we continue to be, for accounting purposes, the owner of vessels included in the transaction (except the Nanook), and as such, we continue to recognize revenue and vessel operating expenses from the charter of these vessels to third parties. The revenue recognized from third-party charters services the financing obligation, resulting in higher interest expense.

Interest expense increased by $82.5 million for the year ended December 31, 2022, as compared to the year ended December 31, 2021. The increase was primarily due to an increase in total principal outstanding, including obligations incurred as a result of the Energos Formation Transaction, under which we incur higher borrowing costs. The total principal balance on outstanding facilities was $4,582.3 million as of December 31, 2022 as compared to total outstanding debt of $3,896.2 million as of December 31, 2021.

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Other (income) expense, net

Other (income) expense, net was $(16.4) million and $10.2 million for the three months ended December 31, 2022 and September 30, 2022, respectively. Other (income) expense, net was $(48.0) million and $(17.2) million for the year ended December 31, 2022 and December 31, 2021, respectively.

Other (income) expense, net recognized in the three months ended December 31, 2022 was primarily comprised of a $20.4 million gain related to the settlement of the foreign currency forward during the fourth quarter of 2022.

Other (income) expense, net recognized in the year ended December 31, 2022 was primarily comprised of a $20.4 million gain related to the settlement of the foreign currency forward during the fourth quarter of 2022 and changes in the fair value of the cross-currency interest rate swap and the interest rate swap resulting in income of $31.0 million.

Loss on extinguishment of debt

Loss on extinguishment of debt was $15.0 million for the year ended December 31, 2022 as a result of the extinguishment of the Vessel Term Loan Facility and sale leaseback financing arrangements with VIEs with proceeds from the Energos Formation Transaction. The Debenture Loan was also extinguished in the third quarter of 2022. There is no additional loss from the three months ended September 30, 2022 to the three months ended December 31, 2022, as there were no such transactions during the fourth quarter of 2022.

Loss on extinguishment of debt was $11.0 million for the year ended December 31, 2021. In November 2021, we exercised our option to terminate the sale leaseback agreement of the Eskimo assumed in the Mergers. The counterparty to this sale leaseback arrangement ("Eskimo SPV") was consolidated in our financial statements subsequent to the Mergers. In connection with the termination of this financing arrangement, we recognized a loss on extinguishment of debt based on the difference between the repurchase price under the sale leaseback arrangement and the carrying value of the net assets of the Eskimo SPV upon deconsolidation.

(Loss) income from equity method investments

We recognized losses from our equity method investments of $117.8 million and $31.7 million and for the three months ended December 31, 2022 and September 30, 2022, respectively. The loss in the fourth quarter of 2022 was primarily the result of the other-than-temporary impairment of our investment in Hilli of $118.6 million, as compared to an additional other-than-temporary impairment of the investment in CELSEPAR of $23.8 million recognized in the third quarter of 2022. Additionally, we began to recognize income from our equity method investment in Energos in the fourth quarter of 2022.

We recognized losses from our equity method investments of $472.2 million for the year ended December 31, 2022. For the year ended December 31, 2021, during the period after the completion of the Mergers, we recognized income from our investments in Hilli and CELSEPAR of $14.4 million. The loss in the current year was primarily driven by an other than temporary impairment of the investment in CELSEPAR and Hilli of $487.8 million recognized in connection with the Sergipe Sale, partially offset by income attributable to our investments in Energos.

Tax provision

We recognized a tax provision for the three months ended December 31, 2022 of $2.8 million compared to a tax provision of $10.0 million for the three months ended September 30, 2022, primarily driven by earnings recognized in jurisdictions with a lower tax rate offset by the realization of deferred tax assets in jurisdictions with a valuation allowance.

The change to the tax provision for the year ended December 31, 2022 resulted principally from the excess benefit on stock compensation, the remeasurement of a deferred income tax liability in conjunction with an internal reorganization and tax benefit associated with the OTTI of the investment in CELSEPAR. For the year ended December 31, 2022, we reflected an excess benefit from stock compensation of $24.4 million. Prior to the completion of the Sergipe Sale, our equity method investment in CELSEPAR was directly held by a subsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil, resulting in a discrete benefit of $76.5 million recognized in the first quarter of 2022. Additionally, in the second and third quarters of 2022, we recognized an impairment on the value of this investment, resulting in a further discrete benefit of $122.4 million. This increase in tax benefit for the

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year ended December 31, 2022 was partially offset by additional tax expense resulting from an increase in pretax income for certain profitable operations.

Liquidity and Capital Resources

We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months and the reasonably foreseeable future. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash generated from certain sales and financing transactions and cash generated from operations. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund developments and transactions. We have historically funded our developments through proceeds from our IPO, debt and equity financing, asset sales and cash from operations, including (capitalized terms defined in “—Long-Term Debt and Preferred Stock.” below):

•In April 2021, we issued $1,500.0 million of 2026 Notes; we also entered into the $200.0 million Revolving Facility that has a term of approximately five years. In February and May 2022, we amended the Revolving Facility to increase the borrowing capacity by $115.0 million and $125.0 million, respectively, for a total capacity under the Revolving Facility of $440.0 million.

•In January 2022, we entered into an agreement for the issuance of the South Power 2029 Bonds secured by our CHP Plant. In 2022, we received proceeds of $221.8 million from the issuance of South Power 2029 Bonds.

•In August 2022, we completed the Energos Formation Transaction, receiving cash proceeds of approximately $1.85 billion. We used $882.5 million of the proceeds for the repayment of the existing Vessel Term Loan and existing sale leaseback facilities.

•Upon closing of the Sergipe Sale in the fourth quarter of 2022, we received proceeds of approximately $530.0 million, inclusive of approximately $20.4 million of proceeds received from two foreign currency contingent, non-deliverable forwards that were entered into to manage foreign currency impacts of the sale.

•To fund the construction of our Barcarena Power Plant, we borrowed $200.0 million in the third and fourth quarters of 2022 under the Barcarena Term Loan.

We have assumed total committed expenditures for all completed and existing projects to be approximately $3,826 million, with approximately $2,473 million having already been spent through December 31, 2022. This estimate represents the committed expenditures for our Fast LNG project, as well as committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, Barcarena Facility, Barcarena Power Plant and Santa Catarina Facility. We expect fully completed Fast LNG units to cost between $800 million and $900 million per unit. 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. 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.

On December 12, 2022, our Board of Directors approved an update to our dividend policy. In connection with the dividend policy update, the Board declared a dividend of $626.3 million, representing $3.00 per Class A share, which was paid in January 2023. Our future dividend policy is within the discretion of our Board of Directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our Board of Directors may deem relevant.

As of December 31, 2022, we have spent approximately $128.6 million to develop the Pennsylvania Facility. Approximately $22.5 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

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Project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2022:

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, 2022. A portion of the debt service amounts of the Vessel Financing Obligation (defined below) is amounts paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above.

Purchase obligations

The Company is 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, 2022.

We have construction purchase commitments in connection with our development projects, including Fast LNG, La Paz Facility, Puerto Sandino Facility, Barcarena Facility and our Santa Catarina Facility. 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. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease.

The Company currently has five vessels under time charter leases with remaining non-cancellable terms ranging from one month to nine years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services.

We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 15 to 25 years. The land site lease is held with an affiliate of the Company and has a remaining term of approximately 22 years with an automatic renewal term of five years for up to an additional 20 years.

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Office space includes space shared with affiliated companies in New York, as well as offices in Houston, New Orleans, and Rio de Janeiro, which have lease terms between one to nine years.

Cash Flows

The following table summarizes the changes to our cash flows for the year ended December 31, 2022 and 2021, respectively:

Cash provided by operating activities

Our cash flow provided by operating activities was $355.1 million for the year ended December 31, 2022, which increased by $270.3 million from cash provided by operating activities of $84.8 million for the year ended December 31, 2021. Our net income for the year ended December 31, 2022, when adjusted for non-cash items, increased by $227.3 million from the year ended December 31, 2021. Changes in working capital accounts, primarily increases in accounts payable and accrued liabilities, also increased the cash provided by operating activities in 2022.

Cash used in investing activities

Our cash flow used in investing activities was $82.7 million for the year ended December 31, 2022, which decreased by $2,190.8 million from cash used in investing activities of $2,273.6 million for the year ended December 31, 2021. Cash outflows from investing activities during the year ended December 31, 2022 were used for continued development of our Fast LNG solution, La Paz Facility, Santa Catarina Facility, and Barcarena Facility. Cash outflows for capital expenditures of $1,174.0 million were partially funded from proceeds of $593.0 million from the sale of the finance lease of the Nanook and proceeds of $500.1 million from the Sergipe Sale.

Cash used for the Mergers, net of cash acquired was $1,586.0 million for the year ended December 31, 2021. Cash outflows for investing activities during the year ended year ended December 31, 2021 were also used for continued development of the Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG Solution.

Cash provided by financing activities

Our cash flow provided by financing activities was $322.0 million for the year ended December 31, 2022, which decreased by $1,495.0 million from cash provided by financing activities of $1,816.9 million for the year ended December 31, 2021. Cash provided by financing activities during the year ended December 31, 2022 primarily consisted of proceeds received from issuance of debt of $2,032.0 million, offset by repayments of debt of $1,520.8 million, payment of dividends of $99.1 million and payments related to tax withholding for share-based compensation of $72.6 million.

Cash provided by financing activities during the year ended December 31, 2021 primarily consisted of proceeds received from the borrowings under the 2026 Notes of $1,500.0 million, draw of $200.0 million on the Revolving Facility, and borrowing of $430.0 million under the Vessel Term Loan Facility. The proceeds received were further offset by repayments of debt, primarily the settlement of the sale-leaseback financing arrangement of the Eskimo for a total payment of $190.5 million, financing fees paid in connection with the borrowings, tax payments for equity compensation made on behalf of employees and dividends paid for the year ended December 31, 2021.

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Long-Term Debt and Preferred Stock

2025 Notes

In September 2020, we issued $1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “2025 Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. We may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.

We used a portion of the net cash proceeds received from the 2025 Notes, together with cash on hand, to repay in full the outstanding principal and interest under previously existing credit agreements and secured and unsecured bonds, including related premiums, costs and expenses.

In December 2020, we issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). As of December 31, 2022 and 2021, remaining unamortized deferred financing costs for the 2025 Notes were $6,649 and $8,804, respectively.

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”) at an issue price equal to 100% of principal. Interest is payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021; 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 on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the first lien obligations under the 2025 Notes.

We used the net proceeds from this offering to fund the cash consideration for the Mergers and pay related fees and expenses.

In connection with the issuance of the 2026 Notes, we incurred $25.2 million 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 of December 31, 2022 and 2021, total remaining unamortized deferred financing costs for the 2026 Notes was $18.4 million and $22.5 million, respectively.

Vessel Financing Obligation

In connection with the Energos Formation Transaction, we entered into long-term time charter agreements for certain vessels. 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, on August 15th, 2022, we accounted for the Energos Formation Transaction as a failed sale-leaseback and has recorded a financing obligation of $1.4billion for consideration received from the Purchaser.

We continue to be the owner for accounting purposes of vessels included in the Energos Formation Transaction (except the Nanook), and as such, we will 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

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obligation; the effective interest rate on this financing obligation of approximately 15.9% includes the cash flows that Energos receives from these third-party charters.

The lease terms for the charter agreements were for periods of up to 20 years. In connection with closing the Energos Formation Transaction, we incurred $10.0 million in origination, structuring and other fees, of which $3.0 million was allocated to the sale of the Nanook and recognized as Other (income) expense, net in the consolidated statements of operations and comprehensive income (loss). Financing costs of $7.0 million were allocated and deferred as a reduction of the principal balance of the financing obligation on the consolidated balance sheets. As of December 31, 2022, the remaining unamortized deferred financing costs for the Vessel Financing Obligation was $6.9 million.

South Power 2029 Bonds

In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100.0 million. The CHP Facility was secured by a mortgage over the lease of the site on which our combined heat and power plant in Clarendon, Jamaica (“CHP Plant”) is located and related security. In January 2022, South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds (“South Power 2029 Bonds”) and subsequently authorized the issuance of up to $285.0 million in South Power 2029 Bonds. The South Power 2029 Bonds are secured by, amongst other things, the CHP Plant. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. During the year ended December 31, 2022, the Company issued $121,824, of South Power 2029 Bonds for a total amount outstanding of $221,824 as of December 31, 2022.

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 are in compliance with all covenants as of December 31, 2022.

In conjunction with obtaining the CHP Facility, we incurred $3.2 million in origination, structuring and other fees. The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds; additional third-party fees associated with such lenders of $0.3 million were recognized as expense in the first quarter of 2022. Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the consolidated balance sheets. As of December 31, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $5.6 million and $3.2 million, respectively.

Barcarena Term Loan

In the third quarter of 2022, certain of our indirect subsidiaries entered into a financing agreement to borrow up to $200.0 million due upon maturity in February 2024 (the “Barcarena Term Loan”); proceeds will be utilized to fund construction of the Barcarena Power Plant. As of December 31, 2022, the loan has been fully funded. Interest is due quarterly, and outstanding borrowings bear interest at a rate equal to the Secured Overnight Financing Rate ("SOFR") plus 4.70%. Additionally, undrawn balances incur a commitment fee of 1.9%.

The obligations under the Barcarena Term Loan are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and New Fortress Energy Inc. has provided a parent company guarantee. We are required to comply with customary affirmative and negative covenants, and the Barcarena Term Loan also provides for

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customary events of default, prepayment and cure provisions. We were in compliance with all covenants as of December 31, 2022.

We incurred $4.0 million of structuring and other fees, and such fees have been deferred as a reduction to the principal balance of the Barcarena Term Loan. As of December 31, 2022, the remaining unamortized deferred financing costs for the Barcarena Term Loan was $3.1 million.

Vessel Term Loan Facility

In September 2021, Golar Partners Operating LLC, an indirect subsidiary of NFE, closed a senior secured amortizing term loan facility (the “Vessel Term Loan Facility”). Under this facility, we borrowed an initial amount of $430.0 million. Loans under the Vessel Term Loan Facility had an interest at a rate of LIBOR plus a margin of 3%. The Vessel Term Loan Facility was repaid in quarterly installments of $15.4 million, with the final repayment date in September 2024.

Obligations under the Vessel Term Loan Facility were guaranteed by GMLP and certain of GMLP’s subsidiaries. Lenders have been granted a security interest covering three floating storage and regasification vessels and four liquified natural gas carriers, and the issued and outstanding shares of capital stock of certain GMLP subsidiaries have been pledged as security. As of December 31, 2021, the aggregate net book value of the three floating storage and regasification vessels and four liquified natural gas carriers pledged as security was approximately $660.6 million.

On August 3, 2022, we exercised the accordion feature under the Vessel Term Loan Facility, drawing $115.0 million, increasing the total principal outstanding to $498.9 million. Net proceeds of $113.9 million were received, and origination and other fees of $1.2 million were deferred as a reduction to the balance of the Vessel Term Loan Facility. As part of the Energos Formation Transaction, all amounts outstanding under the Vessel Term Loan Facility, including this additional principal draw, were repaid. Unamortized deferred financing costs of $5.4 million were recognized as Loss on extinguishment of debt in the consolidated statements of operations and comprehensive income (loss).

Debenture Loan

As part of the Hygo Merger, we assumed non-convertible Brazilian debentures in the aggregate principal amount of BRL 255.6 million due September 2024 (the “Debenture Loan”) bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65%. The Debenture Loan was recognized at fair value of $44.6 million on the date of the Hygo Merger, and the discount recognized in purchase accounting resulted in additional interest expense until maturity. Interest and principal was payable on the Debenture Loan semi-annually on September 13 and March 13.

In the third quarter of 2022, we repaid the outstanding amount of the Debenture Loan of BRL 198.6 million ($39.2 million); unamortized adjustments to the fair value of the Debenture Loan recognized as a result of the Mergers of $0.5 million was recognized as Loss on extinguishment of debt, net in the consolidated statement of operations and comprehensive income (loss).

Revolving Facility

In April 2021, we entered into a $200.0 million senior secured revolving credit facility (the "Revolving Facility"). The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). In February and May 2022, the Revolving Facility was amended to increase the borrowing capacity by $115.0 million and $125.0 million, respectively, for a total capacity under the Revolving Facility of $440.0 million. Letters of credit issued under the $100.0 million letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for us to extend the maturity date once in a one-year increment.

Borrowings under the Revolving Facility bear interest at a rate equal to SOFR plus 0.15% plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and SOFR plus 0.15% plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0% SOFR floor. Borrowings under the Revolving Facility may be prepaid, at our option, at any time without premium.

The obligations under the Revolving Facility are guaranteed by certain of our subsidiaries. We are required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to

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Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 5.0:1.0 for fiscal quarters ending December 31, 2021 until September 30, 2023 and less than 4.0:1.0 for the fiscal quarter ended December 31, 2023 until maturity. We were in compliance with all covenants as of December 31, 2022.

We incurred $5.4 million in origination, structuring and other fees, associated with entry into the Revolving Facility, which includes additional fees incurred to expand the facility in 2022. These costs have been capitalized within Other non-current assets on the consolidated balance sheets. As of December 31, 2022 and December 31, 2021, total remaining unamortized deferred financing costs for the Revolving Facility was $5.2 million and $3.8 million, respectively.

In February 2023, the Revolving Credit Facility was amended to increase the facility by $301.7 million, for a total capacity under the Revolving Facility of $741.7 million. The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed. No changes were made to the maturity date or covenants.

SPV Leasebacks and Loans

As part of the Mergers, we assumed the following debt of entities that were consolidated as VIEs. We were the primary beneficiary of these VIEs, and therefore these loan facilities were presented as part of our consolidated financial statements until these arrangements were terminated in conjunction with the Energos Formation Transaction.

Nanook SPV facility

In September 2018, the Nanook was sold to a subsidiary of CCB Financial Leasing Corporation Limited, Compass Shipping 23 Corporation Limited, and subsequently leased back on a bareboat charter for a term of twelve years. We had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the third anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the twelve-year lease period. The SPV, Compass Shipping 23 Corporation Limited, the owner of the Nanook, had a long-term loan facility due to its parent that was denominated in USD and bore interest at a fixed rate of 2.5%.

Penguin SPV facility

In December 2019, the Penguin was sold to a subsidiary of Oriental Shipping Company, Oriental Fleet LNG 02 Limited, and subsequently leased back on a bareboat charter for a term of six years. We had options to repurchase the vessel throughout the charter term at fixed pre-determined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the six-year lease period. The SPV, Oriental Fleet LNG 02 Limited, the owner of the Penguin, had a long-term loan facility that was denominated in USD and bore interest at LIBOR plus a margin of 1.7%.

Celsius SPV facility

In March 2020, the Celsius was sold to a subsidiary of AVIC International Leasing Company Limited, Noble Celsius Shipping Limited, and subsequently leased back on a bareboat charter for a term of seven years. We had options to repurchase the vessel throughout the charter term at fixed predetermined amounts, commencing from the first anniversary of the commencement of the bareboat charter, with an obligation to repurchase the vessel at the end of the seven-year lease period. The SPV, Noble Celsius Shipping Limited, the owner of the Celsius, had two long-term loan facilities that were denominated in USD. The first facility was paid in quarterly installments over seven years that bore an interest rate of LIBOR plus a margin of 1.8%. The second facility with its parent bore a fixed interest rate of 4.0%.

As part of the Energos Formation Transaction, we exercised our option to repurchase the Penguin, Celsius, and Nanook vessels for a total payment of $380.2 million. After exercising the repurchase options, we no longer had a controlling financial interest in these VIEs and deconsolidated the VIEs. We recognized a loss of $9.1 million from exiting this financing arrangements in Loss on extinguishment of debt, net in the consolidated statements of operations and comprehensive income (loss).

Series A Preferred Units

The 8.75% Series A Cumulative Redeemable Preferred Units issued by GMLP (the “Series A Preferred Units”) remained outstanding following the GMLP Merger and were recognized as non-controlling interest on the consolidated

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balance sheets. Distributions on the Series A Preferred Units are payable out of amounts legally available therefor at a rate equal to 8.75% per annum of the stated liquidation preference. In the event of a liquidation, dissolution or winding up, whether voluntary or involuntary, holders of Series A Preferred Units will have the right to receive a liquidation preference of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of payment, whether declared or not. At any time on or after October 31, 2022, the Series A Preferred Units may be redeemed, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon on the date of redemption, whether declared or not.

Golar Hilli Leaseback

We account for our investment in Hilli LLC under the equity method of accounting. The debt obligations of Hilli LLC and its subsidiaries are not reported separately in our consolidated financial statements. Golar Hilli Corporation (“Hilli Corp”), is a direct subsidiary of Hilli LLC and is a party to a Memorandum of Agreement with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). Under the Hilli Facility, Hilli Corp pays Fortune equal quarterly principal payments plus interest based on LIBOR plus a margin of 4.15%. Our 50% share of Hilli Corp’s indebtedness of $646.5 million amounted to $323.3 million as of December 31, 2022.

As part of the Mergers, we have assumed a guarantee of 50% of the outstanding principal and interest amounts payable by Hilli Corp under the Hilli Leaseback. We also assumed a guarantee of the letter of credit (“LOC Guarantee”) issued by a financial institution in the event of Hilli Corp’s underperformance or non-performance under its tolling agreement. Certain of our subsidiaries are required to comply with the following covenants and ratios: (i) free liquid assets of at least $30 million throughout the Hilli Leaseback period; (ii) a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1; and (iii) a consolidated tangible net worth of $124.0 million. We were in compliance with these covenants as of December 31, 2022.

Letter of Credit Facility

In July 2021, the Company entered into an uncommitted letter of credit and reimbursement agreement with a bank for the issuance of letters of credit for an aggregate amount of up to $75 million. In July 2022, the facility was upsized to $250 million with the ability to increase the total limit by up to $100 million, subject to satisfaction of certain conditions. The letters of credit bear interest at a rate equal to (i) a base rate equal to the higher of the rate last quoted by The Wall Street Journal as the “Prime Rate” and a rate tied to the Federal Reserve Bank of New York, plus 0.50%, plus (ii) an applicable margin of 2.25%. We are using this uncommitted letter of credit and reimbursement agreement to reduce the cash collateral required under existing letters of credit releasing restricted cash. A portion of our restricted cash balance supports existing letters of credit, and this uncommitted letter of credit and reimbursement agreement has replaced these letters of credit and released restricted cash, enhancing our ability to manage the working capital needs of the business.

In February 2023, the uncommitted letter of credit and reimbursement agreement was upsized to $325 million; no changes to interest rates or other terms were made as part of this amendment.

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 equity method investments

Equity method investments are assessed for impairment when events or changes in circumstances indicate a loss in value may have occurred. In 2022, we sold our equity method investment in CELSEPAR, and in the first quarter of 2023, we have announced our intention to exchange our interest in Hilli LLC for cash and NFE shares, and these events have triggered an analysis to review the recoverability of the carrying value. When evidence of loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment has occurred.

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In the second quarter of 2022, we considered whether there was any indication of impairment of the equity method investment in CELSEPAR and the long-lived assets of CEBARRA due to the Sergipe Sale. NFE determined that there was an OTTI of the CELSEPAR equity method investment and an impairment of CEBARRA long-lived assets. The decline in fair value of these investments was driven by the impact of significant increases in risk-free rates to future cash flows, as well as the country specific risk premium observed in connection with where such investment is held, in the second quarter of 2022.

Our estimate of fair value used in the impairment assessments was based on the purchase price in the SPA, as adjusted by contractual adjustments expected to be made to this purchase price at Closing. Judgments used to estimate the fair value included the estimation of expected adjustment to the purchase price and the allocation of the purchase price between CELSEPAR and CEBARRA.

In connection with our analysis for the recoverability of our interest in Hilli, we estimated the fair value of the investment as of December 31, 2022 based on discounted cash flows using an income approach reflecting certain Level 3 inputs. This fair value was corroborated utilizing the terms of the Hilli Exchange linked to market price of NFE shares. The inputs into an income approach, particularly the discount rate, are judgmental, and we considered a range of results using discount rates from 11.5% to 13.5%. Our corroboration of the calculated impairment to other information validated our chosen assumptions. Judgement is also required to determine if the decline in estimated fair values is other than temporary. The decline in fair value of our interest in Hilli was primarily driven by the impact of increases in risk-free rates to future cash flows.

When an other-than-temporary impairment is identified, the excess of the carrying value over the estimated fair value is recognized as an impairment loss in (Loss) income from equity method investments.

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.

The recent geopolitical events in Europe have substantially impacted natural gas and LNG markets with unprecedented price increases and volatility. 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. Additionally, due to current market conditions, we expect that our revenue and results of operations will benefit in the near term from selling cargos into the elevated global LNG market. 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, with our own LNG production from FLNG facilities expected to commence in 2023, we plan to 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

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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.

Allocation of Vessel Financing Obligation

To account for the Energos Formation Transaction, we allocated $1.85 billion of proceeds received between the proceeds received for the sale of a financial asset (net investment in lease of the Nanook) and proceeds that are a financing obligation due to the failed sale leasebacks of ten vessels included in the Energos Formation Transaction. The Company allocated the proceeds using estimates of expected cash flows attributable to each vessel from both third party and NFE charters, which were discounted using counterparty market discount rates. The amortization of the financing obligation was calculated using the effective interest rate method. Upon termination of the NFE's charter of the vessels, we will derecognize the value of the vessel recorded in property, plant and equipment and the remaining financing obligation. The effective interest rate was adjusted to ensure that there is no loss recognized at the end of the charter term.

Share-based compensation

We estimate the fair value of RSUs and performance stock units (“PSUs”) granted to employees and non-employees on the grant date based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model.

For our PSUs, we reassess the probability of the achievement of the performance metric each reporting period to estimate the amount of shares that will vest. Any increase or decrease in share-based compensation expense resulting from an adjustment in the estimated vesting is treated as a cumulative catch-up in the period of adjustment. Our estimate of whether the performance metric will be met is impacted by the timing of our development projects becoming operational and our ability to achieve the expected results of operations, execution of definitive agreements for new projects, costs of LNG and our ability to execute sale of LNG cargos at favorable pricing and facilitate delivery of these cargos during periods of significant volatility in LNG prices. If any of the assumptions or estimates used change significantly, share-based compensation expense may differ materially from what we have recorded in the current period.

Business combinations and goodwill

We evaluate each purchase transaction to determine whether the acquired assets meet the definition of a business. If substantially all of the fair value of gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, then the set of transferred assets and activities is not a business. If not, for an acquisition to be considered a business, it would have to include an input and a substantive process that together significantly contribute to the ability to create outputs. A substantive process is not ancillary or minor, cannot be replaced without significant costs, effort or delay or is otherwise considered unique or scarce. To qualify as a business without outputs, the acquired assets would require an organized workforce with the necessary skills, knowledge and experience that performs a substantive process.

For acquisitions that are not deemed to be businesses, the assets acquired are recognized based on their cost to us as the acquirer, and no gain or loss is recognized. The cost of assets acquired in a group is allocated to individual assets within the group based on their relative fair values and no goodwill is recognized. Transaction costs related to acquisition of assets are included in the cost basis of the assets acquired.

We account for acquisitions that qualify as business combinations by applying the acquisition method. Transaction costs related to the acquisition of a business are expensed as incurred and excluded from the fair value of consideration transferred. Under the acquisition method of accounting, the identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity are recognized and measured at their estimated fair values. The excess of the fair value of consideration transferred over the fair values of identifiable assets acquired, liabilities assumed and noncontrolling interests in an acquired entity, net of fair value of any previously held interest in the acquired entity, is recorded as goodwill.

The Company performs valuations of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity and allocates the purchase price to its respective assets, liabilities and noncontrolling interests. Determining the fair value of assets acquired, liabilities assumed and noncontrolling interests in an acquired entity requires management to use significant judgment and estimates, including the selection of appropriate valuation methodologies, vessel market day rates, and discount rates. The Company estimated the fair value of the vessels acquired in the Mergers using a combination of the

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income approach and the cost approach, which determines the replacement costs for the vessel assets, adjusting for age and condition. Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and unpredictable. As a result, actual results may differ from these estimates. During the measurement period, the Company may record adjustments to acquired assets, liabilities assumed and noncontrolling interests, with corresponding offsets to goodwill. Upon the conclusion of a measurement period, any subsequent adjustments are recorded to earnings.

We use estimates, assumptions and judgments when assessing the recoverability of goodwill. We test for impairment on an annual basis, or more frequently if a significant event of circumstance indicates the carrying amounts may not be recoverable. The assessment of goodwill for impairment may initially be performed based on qualitative factors to determine if it is more likely than not that the fair value of the reporting unit to which the goodwill is assigned is less than the carrying value. If so, a quantitative assessment is performed to determine if an impairment has occurred and to measure the impairment loss.

We completed our annual goodwill impairment evaluation using a qualitative analysis assessment during the fourth quarter of 2022. Under the qualitative assessment, we consider several qualitative factors, including macroeconomic conditions (including changes in interest rates and foreign currency exchange rates), industry and market considerations (including demand for cleaner energy sources and the market price for LNG), the recent and projected financial performance of the reporting unit, as well as other factors.

There was no indication of impairments of goodwill for the year ended December 31, 2022.

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.