New Fortress Energy Inc. 10-Q

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and under similar headings in the Annual Report on Form 10-K for the year ended December 31, 2022 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis. The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included elsewhere in this Quarterly Report. Our financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”). This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in millions. Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries. Overview We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets; additionally, we have expanded our focus to building our modular LNG manufacturing business. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading companies providing power free from carbon emissions by leveraging our global portfolio of integrated energy infrastructure. We discuss this important goal in more detail in our Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a 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. Upon the completion of commissioning, 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 investment in Energos (defined below) is 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 Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina producer in Jamaica, the Puerto Rico Electric Power Authority (“PREPA”), and Comisión Federal de Electricidad (“CFE”), Mexico’s power utility, 31 Table of Contents 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 of LNG per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users. Old Harbour Facility The Old Harbour Facility is an offshore facility consisting of an FSRU that is capable of processing up to 750,000 MMBtus of LNG per day. The Old Harbour Facility commenced commercial operations in June 2019 and supplies natural gas to the 190MW Old Harbour power plant (“Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (“CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay agreement. The Old Harbour Facility also supplies gas directly to Jamalco to utilize in their gas-fired boilers. San Juan Facility Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. The San Juan Facility is near the PREPA San Juan Power Plant and serves as our supply hub for the PREPA San Juan Power Plant and other industrial end-user customers in Puerto Rico. In the first and second quarters of 2023, we entered into agreements with Weston Solutions, Inc. ("Weston") for the installation and operation of approximately 350MW of additional power to be generated at the Palo Seco Power Plant and San Juan Power Plant in Puerto Rico as well as the supply of natural gas. Weston has been contracted by the U.S. Army Corps of Engineers to support the island’s grid stabilization project with additional power capacity to enable maintenance and repair work on Puerto Rico’s power system and grid. We commissioned 150MW of duel-fuel power generation using our gas supply in the second quarter of 2023, and the remaining 200MW was commissioned in September 2023. In the first quarter of 2023, our wholly-owned subsidiary, Genera PR LLC ("Genera"), was awarded a 10-Year contract for the operation and maintenance of PREPA’s thermal generation assets with the goal of reducing costs and improving reliability of power generation in Puerto Rico. We will receive an annual management fee and be eligible for performance-based incentive fees, beginning after the service period under the contract commenced on July 1, 2023. 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 of LNG per day to our 100MW gas-fired modular power units (the “La Paz Power Plant”), which we placed into service in the third quarter of 2023. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu of 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. We executed the final long-form gas sales agreement in the second quarter of 2023, which is subject to certain conditions precedent including the execution of the final agreement to sell the La Paz Power Plant. Miami Facility Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, 32 Table of Contents 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 expected to commence in 2027; 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, which are expected to commence in 2027. Finally, we plan to commence production from our own Fast LNG facilities upon the completion of commissioning . We plan to expand that capacity when additional Fast LNG 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 expected to commence in the fourth quarter of 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 Floating Storage and Regasification Units ("FSRUs"), Floating Storage Units ("FSUs") and LNG carriers ("LNGCs"), which are leased to customers under long-term or spot arrangements. At the expiration of third party charters of vessels owned by Energos Infrastructure (“Energos”), an entity formed in 2022 and described in more detail below, we plan to charter these vessels for our own operational purposes. The results of operations of vessels utilized in our terminal operations are reflected in the Terminals and Infrastructure segment. In August 2022, we completed a transaction (the “Energos Formation Transaction”) with an affiliate of Apollo Global Management, Inc., pursuant to which we transferred ownership of 11 vessel to Energos in exchange for approximately $1.85 billion in cash and a 20% equity interest in Energos. Ten of the vessels were subject to current or future charters with NFE and one vessel (the Nanook ) was not subject to a future NFE charter. The in-place and future charters to NFE of ten vessels prevent the recognition of the sale of those vessels to Energos, and the proceeds associated with these vessels have been treated as a failed sale leaseback. As a result, these ten vessels continue to be recognized on our consolidated balance sheet as Property, plant and equipment, and the proceeds are recognized as debt. Consistent with this treatment as a failed sale leaseback, (i) the third party charter revenues continue to be recognized by us as Vessel charter revenue; (ii) the costs of operating the vessels is included in Vessel operating expenses for the remaining terms of the third-party charters and (iii) such revenues are included as part of debt service for the sale leaseback financing debt and are included in additional financing costs within Interest expense, net. 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 and power plant 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- 33 Table of Contents consuming, challenging and varies in each jurisdiction in which we operate. We obtain required permits, approvals and authorizations in due course in connection with each milestone for our projects. We describe each of our current development projects below. Fast LNG We are currently developing multiple modular liquefaction facilities to provide a source of low-cost supply of LNG to customers around the world. We have designed and are constructing liquefaction facilities for our growing customer base that we believe are both faster and more economical to construct than many traditional liquefaction solutions. 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 site-built alternatives. Semi-permanently moored floating storage unit(s) (FSUs) will provide LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. As noted below, we are also in discussions with CFE to utilize our FLNG design in an onshore application. Our initial Fast LNG units 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. Our first Fast LNG unit is being deployed offshore to Altamira, Mexico, and we expect to deploy additional units over the next two years. We plan to deploy several Fast LNG units at different locations around the world and describe our currently planned projects below. Altamira In the first quarter of 2023, we executed an agreement, which include conditions to effectiveness that have not been satisfied, with CFE to supply natural gas for one FLNG unit located off the coast of Altamira, Tamaulipas, Mexico. The 1.4 million ton per annum (“MTPA”) FLNG unit will utilize CFE’s firm pipeline transportation capacity on the Sur de Texas-Tuxpan Pipeline to receive feedgas volumes. Our first FLNG unit has been installed and connected to the gas pipeline at Altamira, and we are in process of commissioning the project. We have also entered into a non-binding MOU with CFE to develop and operate an onshore liquefied natural gas terminal with up to four 1.4 MTPA FLNG units. The terminal is to be located at the existing Altamira LNG import facility and would source feedgas from the Sur de-Texas Tuxpan Pipeline. The Altamira onshore LNG facility is a world class import facility that will be converted to export LNG similar to other gulf coast regasification terminals. Existing infrastructure at the facility includes two 150,000m3 storage tanks, deepwater marine berth and access to local gas and power networks. Louisiana In addition, we are considering a plan to install up to two FLNG units approximately 16 nautical miles off the southeast coast of Grand Isle, Louisiana. We have filed applications with the U.S. Maritime Administration ("MARAD") and the U.S. Coast Guard to obtain our deepwater port license application for this facility. The facility will be capable of exporting up to approximately 145 billion cubic feet of natural gas per year, equivalent to approximately 2.8 MTPA of LNG. Lakach 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 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. 34 Table of Contents 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 630MW combined cycle thermal power plant to be located in Pará, Brazil, which we own. The Barcarena Power Plant 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 in the first quarter of 2024. 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. For information on this financing agreement, see “—Long-Term Debt and Preferred Stock” in our Annual Report. Santa Catarina Facility 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 the first quarter of 2024. Ireland Facility We intend to develop and operate an LNG facility and power plant on the Shannon Estuary, near Tarbert, Ireland. In April 2023, we were awarded a capacity contract for the development of a power plant for approximately 353 MW of electricity generation with a duration of ten years as part of the auction process operated by Ireland’s Transmission System Operator. The power plant is required to be operational by October 2026. In the third quarter of 2023, An Bord Pleanála, Ireland's planning commission, denied our application for the development of an LNG terminal and power plant. We are challenging this decision. The continued development of this project is uncertain and there are multiple risks, including regulatory risks, that could preclude the development of this project, and the results of these risks could have a material effect on our results of operations. Recent Developments Barcarena Financings In October 2023, certain the Company's Brazilian subsidiaries entered into two long-term financing arrangements fully funding the construction of the Company's power plant located in Pará, Brazil (the "Barcarena Power Plant") . Proceeds received will be used to repay the current Barcarena Term Loan and to pay for all remaining expected construction costs through the planned completion of the Barcarena Power Plant in 2025. The owner of the Barcarena Power Plant entered into a credit agreement with BNDES, the Brazilian Development Bank (the "BNDES Credit Agreement"). The Company is able to borrow up to R$1.8 billion under the BNDES Credit Agreement, segregated into three tranches based on the use of proceeds ("BNDES Term Loan"). Each tranche bears a 35 Table of Contents different rate of interest ranging from 2.61% to 4.41% plus the fixed rate announced by BNDES. No principal payments are required until April 2026 and are due quarterly thereafter until maturity in 2045. The obligations under the BNDES Credit Agreement are guaranteed by certain indirect Brazilian subsidiaries that are constructing the Barcarena Power Plant, and are secured by the Barcarena Power Plant and receivables under the Barcarena Power Plant's PPAs. These Brazilian subsidiaries are required to comply with customary affirmative and negative covenants, and the BNDES Credit Agreement also provides for customary events of default, prepayment and cure provisions. Additionally, the parent of the owner of the Barcarena Power Plant entered into an agreement for the issuance of up to $200 million of convertible debentures maturing in October 2028 ("Barcarena Debentures"). Interest on the Barcarena Debentures is due quarterly, and interest accrues at an annual rate of 12%, increasing 1.25% each year after the third anniversary of issuance. The Company is able to prepay the Barcarena Debentures, subject to customary break funding costs, and the Company is required to utilize certain excess cash flows from the Company's Brazilian operations to prepay principal. The Barcarena Debentures are convertible to shares of one of the Company's indirect Brazilian subsidiaries on the maturity date at the creditors' option, based on the current fair value of this subsidiary's equity at the time of conversion. The obligations under the Barcarena Debentures are guaranteed by certain indirect Brazilian subsidiaries that own Company's LNG regasification terminals located in Pará, Brazil ("Barcarena Terminal") and Santa Catarina, Brazil . NFE has also provided a parent company guarantee that will be released once the Barcarena Terminal commences commercial operations. Brazilian subsidiaries guaranteeing these obligations are required to comply with customary affirmative and negative covenants, and the Barcarena Debentures also provides for customary events of default, prepayment and cure provisions. Term Loan B Credit Agreement On October 30, 2023, the Company entered into a credit agreement (the “Term Loan B Agreement”) pursuant to which the lenders funded term loans to the Company in an aggregate principal amount of $856 million ("Term Loan B"). The proceeds from the Term Loan B issuance will be used to repay the Bridge Term Loans and may be used for working capital and other general corporate purposes. The Term Loan B will mature in October 2028 if the 2025 Notes and 2026 Notes (each as defined in the Annual Report) are refinanced prior to their maturities; if not, the Term Loan B becomes due approximately 60 days prior to the maturity of each the 2025 Notes and 2026 Notes. Quarterly principal payments of approximately $2.1 million begin to be due starting March 2024. The Term Loan B is guaranteed on a senior secured basis by each domestic subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report) and will be guaranteed on a senior secured basis by each foreign guarantor that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility on a post-closing basis. The Term Loan B is and will be secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes, the Company's letter of credit facility and Revolving Facility. Additionally the Term Loan B is secured by assets comprising our first Fast LNG project in Altamira, Mexico. The Term Loan B bears interest at a per annum rate equal to Adjusted Term SOFR (as defined in the Term Loan B Agreement) plus 5.0%. The Company may prepay the Term Loan B at its option subject to prepayment premiums until October 2025 and customary break funding costs. The Company is required to prepay the Term Loan B with the net proceeds of certain asset sales, condemnations, and debt and convertible securities issuances, in each case subject to certain exceptions and thresholds. Additionally, commencing with the fiscal quarter ending December 31, 2024, the Company will be required to prepay the Term Loan B with the Company’s Excess Cash Flow (as defined in the Term Loan B Agreement). The Term Loan B Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. No financial covenant compliance is required under the Term Loan B Agreement. Other Matters On June 18, 2020, we received an order from the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not 36 Table of Contents believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending. On July 18, 2023, we filed for an amendment to the March 19, 2021 and July 15, 2021 FERC orders allowing the continued operation of the San Juan Facility during the pendency of the formal application to allow us to construct and interconnect 220 feet of incremental 10-inch pipeline needed to supply natural gas for temporary power generation solicited through the Puerto Rico Power Stabilization Task Force. On July 31, 2023, FERC issued an order stating that it would not take action to prevent the construction and operation of the pipeline and interconnect. Results of Operations – Three Months Ended September 30, 2023 compared to Three Months Ended June 30, 2023 and Nine Months Ended September 30, 2023 compared to Nine Months Ended September 30, 2022 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 and facilitates measuring and achieving optimal financial performance of our current operations. The principal limitation of this non-GAAP measure is that it excludes significant expenses and income that are required by GAAP. A reconciliation is provided for the non-GAAP financial measure to the most directly comparable GAAP measure, Gross margin. Investors are encouraged to review the related GAAP financial measures and the reconciliation of the non-GAAP financial measure to our Gross margin, and not to rely on any single financial measure to evaluate our business. 37 Table of Contents The tables below present our segment information for the three months ended September 30, 2023 and June 30, 2023, and for the nine months ended September 30, 2023 and September 30, 2022: Three Months Ended September 30, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 447,905 $ 66,557 $ 514,462 $ — $ 514,462 Cost of sales (1)(2) 192,343 — 192,343 (423) 191,920 Vessel operating expenses (4) — 11,613 11,613 — 11,613 Operations and maintenance (4) 60,819 — 60,819 — 60,819 Segment Operating Margin $ 194,743 $ 54,944 $ 249,687 $ 423 $ 250,110 Three Months Ended September 30, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 201,440 Depreciation and amortization 48,670 Consolidated Segment Operating Margin (Non-GAAP) $ 250,110 Three Months Ended June 30, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 495,504 $ 65,841 $ 561,345 $ 561,345 Cost of sales (2) 222,371 — 222,371 3,397 225,768 Vessel operating expenses (4) — 11,443 11,443 11,443 Operations and maintenance (4) 33,697 — 33,697 — 33,697 Segment Operating Margin $ 239,436 $ 54,398 $ 293,834 $ (3,397) $ 290,437 Three Months Ended June 30, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 248,322 Depreciation and amortization 42,115 Consolidated Segment Operating Margin (Non-GAAP) $ 290,437 38 Table of Contents Nine Months Ended September 30, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 1,446,017 $ 230,315 $ 1,676,332 $ (21,394) $ 1,654,938 Cost of sales (1)(2) 488,512 — 488,512 114,114 602,626 Vessel operating expenses (4) — 42,295 42,295 (5,948) 36,347 Operations and maintenance (4) 121,187 — 121,187 — 121,187 Segment Operating Margin $ 836,318 $ 188,020 $ 1,024,338 $ (129,560) $ 894,778 Nine Months Ended September 30, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 769,618 Depreciation and amortization 125,160 Consolidated Segment Operating Margin (Non-GAAP) $ 894,778 Nine Months Ended September 30, 2022 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 1,711,241 $ 337,626 $ 2,048,867 $ (226,964) $ 1,821,903 Cost of sales (2) 909,938 — 909,938 (35,409) 874,529 Vessel operating expenses (4) 11,178 71,029 82,207 (20,297) 61,910 Operations and maintenance (4) 89,861 — 89,861 (24,170) 65,691 Segment Operating Margin $ 700,264 $ 266,597 $ 966,861 $ (147,088) $ 819,773 Nine Months Ended September 30, 2022 (in thousands of $) Consolidated Gross margin (GAAP) $ 713,334 Depreciation and amortization 106,439 Consolidated Segment Operating Margin (Non-GAAP) $ 819,773 (1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are an economic hedge of commodity purchases and sales, and realized lo sses of $0.3 million and realized gains of $141.6 million for the three and nine months ended September 30, 2023, respectively, were recognized as a reduction to Cost of sales in the segment measure. We recognized unrealized gains of $0.4 million and unrealized losses of $107.9 million on the mark-to-market value of derivative transactions for the three and nine months ended September 30, 2023, respectively, and these gains and losses reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated stat ements of operations and comprehensive income (loss) . We have excluded contract acquisition costs that do not meet the criteria for capitalization from the segment measure. Contract acquisition costs of $6.2 million for the three and nine months ended September 30, 2023 reconcile Cost of sales in the segment measure to Cost of sales in the condensed consolidated statements of operations and comprehensive income (loss). 39 Table of Contents (2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income (loss) . (3) Consolidation and Other adjusts for the inclusion of the effective share of revenues, expenses and operating margin attributable to our 50% ownership of Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) and the common units of Hilli LLC in the segment measure, prior to the disposition to these investments, the exclusion of the unrealized mark-to-market gain or loss on derivative instruments, and the exclusion of non-capitalizable contract acquisition costs. (4) Operations and maintenance and Vessel operating expenses are directly attributable to revenue-producing activities of our terminals and vessels and are included in the calculation of Gross margin defined under GAAP. Terminals and Infrastructure Segment Three Months Ended, (in thousands of $) September 30, 2023 June 30, 2023 Change Total revenues $ 447,905 $ 495,504 $ (47,599) Cost of sales (exclusive of depreciation and amortization) 192,343 222,371 (30,028) Operations and maintenance 60,819 33,697 27,122 Segment Operating Margin $ 194,743 $ 239,436 $ (44,693) Nine Months Ended, (in thousands of $) September 30, 2023 September 30, 2022 Change Total revenues $ 1,446,017 $ 1,711,241 $ (265,224) Cost of sales (exclusive of depreciation and amortization) 488,512 909,938 (421,426) Vessel operating expenses — 11,178 (11,178) Operations and maintenance 121,187 89,861 31,326 Segment Operating Margin $ 836,318 $ 700,264 $ 136,054 Total revenue Total revenue for the Terminals and Infrastructure Segment decreased by $47.6 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. The decrease was primarily driven by decreases to revenue from LNG cargo sales to third parties, partially offset by additional gas sales in Puerto Rico and increases to the Henry Hub index. The index forms a portion of the pricing to invoice most of our customers in this segment. The decrease in revenue in third quarter of 2023 when compared to the second quarter of 2023 was primarily attributable to the following: • We had no revenue from LNG cargo sales for the three months ended September 30, 2023, decreasing from $267.8 million for the three months ended June 30, 2023, as we were able to utilize all LNG purchased under our long-term supply contracts in our terminal operations. Such decrease was offset by increases to revenue in the three months ended September 30, 2023 when compared to the three months ended June 30, 2023, due to the following: • Volumes delivered to downstream terminal customers increased from 14.0 TBtus in the second quarter of 2023 to 20.1 TBtu in the third quarter of 2023. We continue to support the grid stabilization project in Puerto Rico, and we recognized a full quarter of operations for our Palo Seco Power Plant during the third quarter. We also completed the commissioning of additional power assets at the San Juan Power Plant in September. Additionally, i n August 2023, we placed our La Paz Power Plant into service, and we began to recognize revenue from power sales from this plant in the local spot market. 40 Table of Contents • The average Henry Hub index pricing used to invoice our downstream customers increased by 22% for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Total revenue for the Terminals and Infrastructure Segment decreased by $265.2 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The decrease was primarily driven by lower LNG cargo sales, no pro rata share of revenue from our former investment in CELSEPAR and a reduction in the Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment. The decrease in revenue was partially offset by increased revenue from sales to downstream terminal customers. The decrease in revenue in the nine months ended September 30, 2023 when compared to the nine months ended September 30, 2022 was primarily attributable to the following: • Our LNG cargo sales to third parties decreased by $327.7 million for the nine months ended September 30, 2023, decreasing from $944.8 million for the nine months ended September 30, 2022 to $617.1 million nine months ended September 30, 2023. In the third quarter of 2023, we were able to utilize all LNG purchased under our long-term supply contracts in our terminal operations. • After the completion of the sale of our investment in CELSEPAR in the fourth quarter of 2022, we no longer recognize revenue from this investment in our segment measure. Our share of revenue from CELSEPAR was $148.3 million for the nine months ended September 30, 2022, which was primarily comprised of fixed capacity payments received under related PPAs. • The average Henry Hub index pricing used to invoice our downstream customers decreased by 60% for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 Such decrease was offset by increases to revenue in the nine months ended September 30, 2023 when compared to the nine months ended September 30, 2022, due to the following: • Volumes delivered to downstream customers were 46.1 TBtu for the nine months ended September 30, 2023 as compared to 28.5 TBtu for the nine months ended September 30, 2022, and these increased volumes were primarily attributable to our operations in Jamaica, Puerto Rico and Mexico. • In the prior year, maintenance activities significantly lowered consumption at our facilities; there has been no significant maintenance downtime during 2023. The maintenance downtime in the prior year was across our facilities, including downtime at our CHP Plant for unplanned maintenance, downtime at our Montego Bay Facility due to a reconfiguration of our assets required by the Port of Montego Bay and maintenance at PREPA's San Juan Power Plants. Volumes delivered across from these facilities increased by 12.8 TBtu as compared to the nine months ended September 30, 2022. • In May 2023, we began to support the grid stabilization project in Puerto Rico, commissioning power generation assets at the Palo Seco Power Plant. In September 2023, we finished commissioning additional power generation assets at the San Juan Power Plant. We have consumed 4.7 TBtu at these power plants during the nine months ended September 30, 2023 as part of this project. 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 by $30.0 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023, which was attributable to the following: • We did not incur any cost of LNG purchased from third parties for LNG cargo sales, decreasing our cost by $76.9 million during the third quarter of 2023. 41 Table of Contents • Vessel costs increased by $23.0 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Vessels were used for commissioning of our La Paz Power Plant and our enhanced supply chain for our Puerto Rican operations in the second quarter, and such vessel costs were capitalized. As these projects became operational in the third quarter we recognized higher expense associated with these vessels. Further, certain vessels were placed into service at our terminals during the third quarter resulting in higher vessel charter costs. • Increase in cost of LNG purchased from third parties for sale to our downstream customers of $18.4 million related to higher terminal sales; volumes delivered to our downstream customers increased by approximately 43% in the current quarter. Our cost to deliver these volumes decreased to $6.76 per MMBtu for the three months ended September 30, 2023 from $8.08 per MMBtu for the three months ended June 30, 2023. Cost of sales decreased by $421.4 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022, which was attributable to the following: • We incurred decreased cost of LNG purchased from third parties for LNG cargo sales of $212.6 million during the nine months ended September 30, 2023, resulting from no LNG cargo sales in the third quarter as well as lower cost under our LNG supply contracts for cargos sold earlier in 2023. • Realized gains of $141.6 million from the settlement of commodity swap transactions, entered into as an economic hedge to reduce the market risks associated with commodity prices, were included as reduction of cost of sales. For segment performance measures, unrealized mark to market gains and losses are excluded until settled. • Vessel costs decreased by $37.6 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 primarily due to the capitalization of vessel costs for the commissioning of development projects, as well as, vessel costs recognized as inventory when our vessels are used to transport inventory from a supplier's facility to our storage locations and terminals. • Cost of sales for the nine months ended September 30, 2022 included $28.6 million of our share of cost of sales from our investment in CELSEPAR, which was primarily comprised of LNG costs to fuel a power plant owned by CELSEPAR. • We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $15.3 million during the nine months ended September 30, 2023 due to increased volumes delivered; we delivered 62% more volumes to our downstream terminal customers in the current period as compared to the nine months ended September 30, 2022. While we delivered significantly more volumes to our downstream customers, our pricing to purchase LNG for delivery to such customers was substantially lower, decreasing to $7.26 per MMBtu for the nine months ended September 30, 2023 from $10.78 per MMBtu for the nine months ended September 30, 2022. The weighted-average cost of our LNG inventory balance to be used in our downstream terminal operations as of September 30, 2023 and December 31, 2022 was $7.30 per MMBtu and $10.42 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. For the nine months ended September 30, 2022, we incurred $11.2 million of vessel operating expenses in this segment; we did not incur vessel operating costs in this segment during the nine months ended September 30, 2023. Operations and maintenance Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance increased by $27.1 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Starting in the third quarter of 2023, our subsidiary, Genera, began to provide 42 Table of Contents operations and maintenance services for PREPA's thermal generation assets, and we recognized payroll and other operating costs of $16.3 million. Under our contract with PREPA, we pass all of these costs onto PREPA, and such billings are recognized as revenue. In the third quarter, we also undertook activities to ensure that we have LNG supply available for our expanded Puerto Rican operations, including leasing berth space to place a storage vessel to service Puerto Rico, and we incurred additional lease cost associated with this berth space in the third quarter of 2023. Operations and maintenance increased $31.3 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 . The increase was primarily attributable to reimbursable payroll and operating costs of Genera and increased lease costs associated with our Puerto Rican operations incurred in the third quarter of 2023. Additionally, we leased turbines to generate power at the Palo Seco Power Plant as part of the grid stabilization project in Puerto Rico, increasing operations and maintenance costs when compared to the prior year. These increases were partially offset by the exclusion of our share of Operations and maintenance from the investment in CELSEPAR; after the sale of our investment in CELSEPAR in the fourth quarter of 2022, we do not include these costs during nine months ended September 30, 2023. Ships Segment Three Months Ended, (in thousands of $) September 30, 2023 June 30, 2023 Change Total revenues $ 66,557 $ 65,841 $ 716 Vessel operating expenses 11,613 11,443 170 Segment Operating Margin $ 54,944 $ 54,398 $ 546 Nine Months Ended, (in thousands of $) September 30, 2023 September 30, 2022 Change Total revenues $ 230,315 $ 337,626 $ (107,311) Vessel operating expenses 42,295 71,029 (28,734) Segment Operating Margin $ 188,020 $ 266,597 $ (78,577) 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 busine ss operations. On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of our investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $100 million in cash (the "Hilli Exchange"). In the fourth quarter of 2022, we recognized a loss on the investment in the Hilli of $118.6 million; this loss was recognized in Loss from equity method investments in the consolidated statements of operations and comprehensive income (loss) . Upon completion of the Hilli Exchange during the first quarter of 2023, we recognized an additional loss on disposal of $37.4 million, which was included in Other (income) expense, net. As a result of the Hilli Exchange we no longer have an ownership interest in the Hilli . NFE shares received from GLNG were cancelled upon the closing of the Hilli Exchange. As of September 30, 2023, four FSRUs and two LNG carriers were leased to customers under long-term or spot arrangements. In July 2023, we sold the vessel Golar Spirit for a total consideration of $15.8 million resulting in a gain of $7.8 million. The gain on sale is included in Other (income) expense, net in the condensed consolidated statements of operations and comprehensive income (loss). The Mazo continues to be in cold lay-up, and no vessel charter revenue was generated from the vessel. 43 Table of Contents Total revenue Total revenue for the Ships segment increased $0.7 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023 . During the third quarter, there were no reclassifications of vessels out of the Ships segment; there were also no significant changes the vessel charters. Total revenue for the Ships segment decreased $107.3 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The decrease in revenue was primarily the result of the sale of the Nanook as part of the Energos Formation Transaction; we no longer recognize revenue related to the Nanook in 2023. One of our vessel charters was renewed at the beginning of 2023 at a lower rate; additionally the charters for two vessels concluded in the first quarter of 2023, lowering vessel revenue for the full nine months ended September 30, 2023 . We plan to utilize these vessels in our operations following conversion and other upgrades starting later in 2023. Vessel operating expenses Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli prior to the Hilli Exchange discussed above. We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter. Vessel operating expenses increased $0.2 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Vessel operating expenses decreased $28.7 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022 . The decrease in vessel operating expenses was primarily due to lower costs related to the Hilli after the Hilli Exchange at the end of the first quarter of 2023. Vessel operating expenses also decreased as a result of the sale of the Nanook as part of the Energos Formation Transaction; we recognized vessel operating expenses related to the Nanook during 2022 and no longer recognize vessel operating expenses related to the Nanook in 2023. 44 Table of Contents Other operating results Three Months Ended, Nine Months Ended, (in thousands of $) September 30, 2023 June 30, 2023 Change September 30, 2023 September 30, 2022 Change Selling, general and administrative $ 49,107 $ 55,803 $ (6,696) $ 157,048 $ 165,952 $ (8,904) Transaction and integration costs 2,739 1,554 1,185 4,787 12,387 (7,600) Depreciation and amortization 48,670 42,115 6,555 125,160 106,439 18,721 Asset impairment expense — — — — 48,109 (48,109) Total operating expenses 100,516 99,472 1,044 286,995 332,887 (45,892) Operating income 149,594 190,965 (41,371) 607,783 486,886 120,897 Interest expense 64,822 64,396 426 200,891 156,344 44,547 Other (income) expense, net (2,271) (6,584) 4,313 16,150 (31,613) 47,763 Loss on extinguishment of debt, net — — — — 14,997 (14,997) Income before income from equity method investments and income taxes 87,043 133,153 (46,110) 390,742 347,158 43,584 Income (loss) from equity method investments 489 2,269 (1,780) 12,738 (354,426) 367,164 Tax provision (benefit) 25,194 15,322 9,872 69,476 (126,249) 195,725 Net income $ 62,338 $ 120,100 $ (57,762) $ 334,004 $ 118,981 $ 215,023 Selling, general and administrative Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors, and screening costs for projects that are in initial stages and development is not yet probable. Selling, general and administrative decreased $6.7 million for the three months ended September 30, 2023, compared to the three months ended June 30, 2023. We have decreased headcount supporting our administrative activities, and we recognized a decrease to our estimate of annual incentive compensation due to the headcount reduction in the third quarter of 2023. Selling, general and administrative decreased $8.9 million for the nine months ended September 30, 2023 as compared to the nine months ended September 30, 2022. The decreases were primarily due to lower share-based compensation expense in 2023, offset by higher payroll costs incurred for the nine months ended September 30, 2023 prior to our headcount reduction. Transaction and integration costs For the three months ended September 30, 2023, we did not incur significant transaction and integration costs. For the nine months ended September 30, 2023, we incurred $4.8 million for transaction and integration costs, as compared to $12.4 million for the nine months ended September 30, 2022. For the nine months ended September 30, 2022, we incurred transaction and integration costs primarily associated with the Sergipe Sale. There were no such significant transactions for the nine months ended September 30, 2023. Depreciation and amortization Depreciation and amortization increased $6.6 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023 and increased $18.7 million for the nine months ended September 30, 2023 as 45 Table of Contents compared to the nine months ended September 30, 2022. In the second quarter of 2023, we began to place assets in service as part of the grid stabilization project in Puerto Rico, including turbines we own, as well a turbines we leased under a finance lease, at the Palo Seco Power Plant. These assets were placed into service in the May 2023, and we recognized a full quarter of depreciation in the third quarter of 2023. Asset impairment expense As a result of our acquisition of Hygo Energy Transition Limited in 2021, we recognized long-lived assets associated with the expansion of the Sergipe Power Plant. During the nine months ended September 30, 2022, we recognized asset impairment expense of $48.1 million, as the fair value of these assets was less than the carrying value, and the asset group was held for sale. There were no such transactions for the nine months ended September 30, 2023. Interest expense Interest expense increased by $0.4 million for the three months ended September 30, 2023 as compared to the three months ended June 30, 2023. Increased interest expense due to borrowings under our expanded Revolving Facility and the Bridge Term Loan, as well as the issuance of the Equipment Notes and the Short-term Borrowings (each as defined below), were mostly offset by increases in capitalized interest. Interest expense increased by $44.5 million for the nine months ended September 30, 2023 , as compared to the nine months ended September 30, 2022 . The increase was primarily due to an increase in total principal outstanding due to additional principal balance outstanding, including obligations under the Energos Formation Transaction. The total principal balance on outstanding facilities was $6.2 billion as of September 30, 2023 as compared to total principal outstanding of $4.5 billion as of September 30, 2022. Other (income) expense, net Other (income) expense, net was $(2.3) million and $(6.6) million three months ended September 30, 2023, and June 30, 2023, respectively. Other expense (income), net was $16.2 million and $(31.6) million for the nine months ended September 30, 2023 and September 30, 2022, respectively. Other income recognized in the three months ended September 30, 2023 was primarily comprised of a $7.8 million gain on the sale of the Golar Spirit and interest income. This income was partially offset by foreign currency remeasurement losses and realized losses on the sale of certain investments in equity securities. Other expense recognized in the nine months ended September 30, 2023 was primarily comprised of a $37.4 million loss on disposal of Hilli equity method investment in the Hilli Exchange. This loss was partially offset by interest income and foreign currency remeasurement net gains. Tax provision We recognized a tax provision for the three months ended September 30, 2023 of $25.2 million compared to a tax provision of $15.3 million for the three months ended June 30, 2023. Our effective tax rate for the three months ended September 30, 2023 was 28.8% compared to 11.3% for the three months ended June 30, 2023. Our tax provision and effective tax rate primarily increased due to additional expected income tax expense related to certain of the Company's foreign subsidiaries. We recognized a tax provision of $69.5 million for the nine months ended September 30, 2023 compared to a tax benefit of $126.2 million for the nine months ended September 30, 2022. The significant tax benefit recognized in 2022 was primarily driven by significant discrete items, including the remeasurement of a deferred tax liability in conjunction with an internal reorganization and the tax benefit associated with the other-than-temporary impairment on our investment in CELSEPAR. We have not recognized any significant discrete items through the third quarter of 2023. Income (loss) from equity method investments We recognized income from our equity method investments of $0.5 million and $2.3 million for the three months ended September 30, 2023 and June 30, 2023, respectively. We completed the Hilli Exchange in the first quarter of 2023, and as such, income from equity method investments in the second and third quarters of 2023 is wholly comprised of 46 Table of Contents earnings from our investment in Energos. Our share of earnings from Energos decreased in the third quarter due to additional vessel operating expenses incurred by Energos. We recognized income of $12.7 million from our equity method investments in the nine months ended September 30, 2023 compared to loss of $354.4 million for the nine months ended September 30, 2022. In connection with the announcement of the sale of our investment in CELSEPAR in 2022, we recognized an other than temporary impairment of the investment in CELSEPAR of $369.2 million; we did not have any such impairments impacting the earnings from our equity method investments in 2023. Factors Impacting Comparability of Our Financial Results Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons: • Our historical financial results do not reflect our Fast LNG solution that will lower the cost of our LNG supply. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 98% of our LNG volumes from third parties for the nine months ended September 30, 2023. We anticipate that the deployment of Fast LNG floating liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third-party suppliers. We expect to deploy our first Fast LNG unit upon the completion of commissioning. • Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the three and nine months ended September 30, 2023 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We have placed our La Paz Facility in service, and in the third quarter of 2023, we placed the La Paz Power Plant into service. We have executed agreements to extend and amend our supply of natural gas to multiple CFE power generation facilities in Baja California Sur, and as such, our revenue and results of operations have begun to be impacted by our operations in Mexico. We are also continuing to develop our Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and Ireland Facility, and our current results do not include revenue and operating results from these projects. Additionally, we began to deliver power to the Puerto Rican grid from the Palo Seco Power Plant as part of the grid stabilization project in the second quarter of 2023. At the end of September 2023, we placed additional power generation assets in service at the San Juan Power Plant. We expect that our power generation assets at both the Palo Seco Power Plant and at the San Juan Power Plant will operate at full capacity, and we expect that our revenue and results of operations will benefit from significant gas consumption required to operate these assets. • Our historical financial results include the results from our investments in the common units of Hilli LLC and CELSEPAR. On March 15, 2023, we completed the Hilli Exchange, and in the fourth quarter of 2022, we sold our interest in CELSEPAR, the indirect owner of the Sergipe Power Plant in Brazil. As a result of these transactions, we no longer have any ownership interest in either the Hilli or the Sergipe Power Plant, and their results will no longer be included in NFE's results of 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. Our significant capital projects, primarily our first FLNG unit, are nearing completion, and as with many capital projects, a significant portion of the overall capital spending becomes due near the completion of the project. We have also incurred significant capital costs to deploy 350MW of temporary power as part of the grid stabilization project in Puerto Rico. We expect the current working capital position to improve based on: (1) following September 30, 2023, we have borrowed under our new Term Loan B Agreement, totaling $856 million; (2) we have fully funded the construction of our Barcarena Power Plant with new long-term financing in Brazil; (3) our credit agreements allow for proceeds from the sale of assets to be reinvested in our business, and we have significant non-core assets that could be used to fund our developments; (4) expected cash flows generated from the temporary power project and from sales of our own LNG 47 Table of Contents generated by our first deployed Fast LNG unit; and (5) our relationships with certain significant vendors constructing our Fast LNG assets have allowed us to extend our payment terms to better align with the expected completion of Fast LNG. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities, cash generated from certain sales and financing transactions and cash generated from operations . We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund our developments and transactions. We have assumed total committed expenditures for all completed and existing projects to be approximately $6,162 million, with approximately $4,815 million having already been paid through September 30, 2023. 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, Santa Catarina Facility and committed capital expenditures to support our grid stabilization project in Puerto Rico. We expect fully completed Fast LNG units to cost between $1.0 billion and $1.6 billion 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. For example, expected spending for our second and third Fast LNG units that is not currently contracted is excluded from the estimated committed spending. Each Fast LNG completion is subject to permitting, various contractual terms, project feasibility, our decision to proceed and timing. We carefully manage our contractual commitments, the related funding needs and our various sources of funding including cash on hand, cash flow from operations, and borrowings under existing and future debt facilities. We may also enter into other financing arrangements to generate proceeds to fund our developments. As of September 30, 2023, we have spent approximately $128.6 million to develop the Pennsylvania Facility. Approximately $22.5 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $106.1 million, has been capitalized, and to date, we have repurposed approximately $16.8 million of engineering and equipment to our Fast LNG project. We intend to apply for updated permits for the Pennsylvania Facility with the aim of obtaining these permits to coincide with the commencement of construction activities. 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 during the first quarter of 2023. Additionally, we declared and paid quarterly dividends totaling $61.5 million during the nine months ended September 30, 2023, representing $0.10 per Class A share. 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. In the third quarter of 2023, our Board of Directors reinstated a dividend policy of targeting a quarterly dividend of $0.10 per share. 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 September 30, 2023. (in thousands of $) Total Less than Year 1 Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 8,525,237 $ 225,540 $ 3,550,767 $ 2,177,844 $ 2,571,086 Purchase obligations 14,968,923 645,109 2,237,465 1,412,110 10,674,239 Lease obligations 600,005 47,555 255,500 108,502 188,448 Total $ 24,094,165 $ 918,204 $ 6,043,732 $ 3,698,456 $ 13,433,773 Long-term debt obligations 48 Table of Contents For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report. The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of September 30, 2023. A portion of our long-term debt obligations will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above. Subsequent to September 30, 2023, we entered into the BNDES Credit Agreement, Barcarena Debentures and Term Loan B Credit Agreement (each defined and described in Note 24. Subsequent events). Proceeds from these new credit arrangements have been or will be used to refinance the Bridge Term Loan and the Barcarena Term Loan on a long term basis, and as such, these principal balances have been shown as non-current on the condensed consolidated balance sheets as of September 30, 2023. Purchase obligations We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of September 30, 2023. We have construction purchase commitments in connection with our development projects, including our Fast LNG project, La Paz Facility, Puerto Sandino Facility, Barcarena Facility, Santa Catarina Facility and committed capital expenditures to support our grid stabilization project in Puerto Rico. Commitments included in the table above include commitments under engineering, procurement and construction contracts where a notice to proceed has been issued. Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space, gas turbines and a land lease. Cash Flows The following table summarizes the changes to our cash flows for the nine months ended September 30, 2023 and 2022, respectively : Nine Months Ended September 30, (in thousands of $) 2023 2022 Change Cash flows from: Operating activities $ 537,184 $ 91,105 $ 446,079 Investing activities (2,065,562) (195,960) (1,869,602) Financing activities 924,072 249,710 674,362 Net (decrease) increase in cash, cash equivalents, and restricted cash $ (604,306) $ 144,855 $ (749,161) Cash provided by operating activities Our cash flow provided by operating activities was $537.2 million for the nine months ended September 30, 2023, which increased by $446.1 million from cash provided by operating activities of $91.1 million for the nine months ended 49 Table of Contents September 30, 2022. The increase in cash provided by operating activities for the nine months ended September 30, 2023 was primarily driven by changes in working capital, including improved collection of receivables and the settlement of a significant commodity derivative, as well as significant cash receipts under our temporary power agreements that are required to be deferred as contract liabilities. Cash (used in) investing activities Our cash flow used in investing activities was $2,065.6 million for the nine months ended September 30, 2023, which increased by $1,869.6 million from cash used in investing activities of $196.0 million for the nine months ended September 30, 2022. Cash outflows for investing activities during the nine months ended September 30, 2023 were used primarily for continued development of our Fast LNG project and assets to service the grid stabilization project in Puerto Rico. Cash outflows were offset by proceeds of $100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange, as well as proceeds received from the sale of the Spirit and a portion of our investment in equity securities. Cash outflows for investing activities during the nine months ended September 30, 2022 were used for continued development of our Fast LNG project, Santa Catarina Facility, and Barcarena Facility. Cash outflows were offset by proceeds of $593.0 million from the sale of the finance lease of the Nanook . Cash provided by financing activities Our cash flow provided by financing activities was $924.1 million for the nine months ended September 30, 2023, which increased by $674.4 million from cash provided by financing activities of $249.7 million for the nine months ended September 30, 2022. In December 2022, our Board of Directors approved and declared a dividend of $626.3 million, representing $3.00 per Class A share; such dividend payment was made in January 2023. We have borrowed under our expanded Revolving Facility, Bridge Term Loans, Equipment Notes, as well as short-term borrowings under repurchase arrangements for total additional borrowings of $1,768.7 million. Such borrowings were primarily used to fund the ongoing development of our Fast LNG project and to support our grid stabilization project in Puerto Rico. Increased borrowings during 2023 were offset by repayments of debt totaling $104.5 million, primarily the repayment of short-term borrowings under repurchase arrangements. Cash provided by financing activities during the nine months ended September 30, 2022 was due to proceeds from issuance of debt of $1.9 billion, offset by repayments of debt of $1.5 billion, payment of dividends of $75.1 million and payments related to tax withholdings for shared-based compensation of $72.6 million. Long-Term Debt and Preferred Stock The terms of our debt instruments and associated obligations have been described in our Annual Report. There have been no significant changes to the terms of our outstanding debt, covenant requirements or payment obligations, other than described below. Bridge Term Loan Credit Agreement On August 3, 2023, we entered into a Bridge Term Loan Credit Agreement (the “Bridge Term Loan Agreement”) pursuant to which the lenders funded term loans (the “Bridge Term Loans”) to the Company in an aggregate principal amount of $400 million. Bridge Term Loan proceeds may be used for working capital and other general corporate purposes. The Bridge Term Loans will mature on August 1, 2024 and are payable in full on the maturity date. The Bridge Term Loans were repaid in full without penalty using proceeds from the Term Loan B which closed after September 30, 2023. The Bridge Term Loans were guaranteed on a senior secured basis by each domestic and foreign subsidiary that is a guarantor under the 2025 Notes, 2026 Notes and Revolving Facility (each as defined in the Annual Report). The Bridge Term Loans were secured by substantially the same collateral as the first lien obligations under the 2025 Notes, 2026 Notes and Revolving Facility. The Bridge Term Loan Agreement contained usual and customary representations and warranties, and usual and customary affirmative and negative covenants, including requirements to maintain certain levels of total debt to capitalization and total first lien debt to EBITDA, and the ratios required to be maintained were consistent with the requirements under the Revolving Facility. 50 Table of Contents Equipment Notes In June 2023, we executed a Master Loan and Security Agreement with a lender to borrow up to $200.0 million under promissory notes secured by certain turbines acquired in the first quarter of 2023 to support the grid stabilization project in Puerto Rico (the “Equipment Notes”). During the second and third quarters of 2023, we borrowed the full capacity bearing interest at approximately 7.7%, and the principal is partially repayable in monthly installments over the 36 month term of the loan with the balance due upon maturity in July 2026. The Equipment Notes contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The Equipment Notes do not contain any restrictive financial covenants. EB-5 Loan Agreement On July 21, 2023, we entered into a loan agreement under the U.S. Citizenship and Immigration Services EB-5 Program (“EB-5 Loan Agreement”) to pay for the development and construction of a new green hydrogen facility in Texas. The maximum aggregate principal amount available under the EB-5 Loan Agreement is $100.0 million, and outstanding borrowings bear interest at a fixed rate of 4.75%. The loan matures in 5 years from the initial advance with an option to extend the maturity by two one-year periods. It is expected that the loan will be secured by NFE's green hydrogen facility, and NFE has provided a guarantee of the obligations under the EB-5 Loan Agreement. In the third quarter of 2023, $37.9 million was funded under the EB-5 Loan Agreement. The EB-5 Loan Agreement contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants. The EB-5 Loan Agreement does not contain any restrictive financial covenants. Short-term Borrowings We may, from time to time, enter into sales and repurchase agreements with a financial institution, whereby we sell to the financial institution an LNG cargo and we concurrently enters into an agreement to repurchase the same LNG cargo immediately with the repurchase price payable at a future date, generally not to exceed 90-days from the date of the sale and repurchase (the “Short-term Borrowings”). As of September 30, 2023, we had $161.8 million due under repurchase arrangements with a weighted average interest rate of 9.74%. Revolving Facility In the first three quarters of 2023, we entered into amendments of our Revolving Facility which increased the commitments by $426.6 million, for a total capacity of $866.6 million. The interest rate for borrowings under the Revolving Facility based on the current usage of the facility has not changed, and no changes were made to the maturity date or covenants. In conjunction with these amendments, we incurred an additional $7.0 million in fees which have been capitalized within Other non-current assets. Debt and lease restrictions We are required to comply with covenants under the Revolving Facility and letter of credit facility, including requirements to maintain Debt to Capitalization Ratio of less than 0.7:1.0, and for quarters in which the Revolving Facility is greater than 50% drawn, the Debt to Annualized EBITDA Ratio must be less than 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. We were in compliance with all covenants as of September 30, 2023. Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of September 30, 2023 , there have been no significant changes to our critical accounting estimates since our Annual Report. Recent Accounting Standards For descriptions of recently issued accounting standards, see “Note 3. Adoption of new and revised standards” to our notes to condensed consolidated financial statements included elsewhere in this Quarterly Report. 51 Table of Contents