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. Starting in the third quarter of 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 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”), a subsidiary of Federal 26 Table of Contents 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 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. 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”) following the start of operations. 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 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 second quarter of 2023. Miami Facility Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 8,300 MMBtu of LNG per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers. 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 27 Table of Contents 2026 and 2027. Finally, we plan to commence our own Fast LNG production in the third quarter of 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 the third 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 FSRUs and LNG carriers, 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 describe in more detail below, we plan to charter these vessels for our own use. We exclude these vessels from our Ships segment and include them in our Terminals and Infrastructure segment once we begin to use the vessels for our own operational purposes. One LNG carrier and one 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 (the “Energos Formation Transaction”). As a result of the Energos Formation Transaction, we own approximately a 20% equity interest in Energos, and 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 vessels, the terms of which commence upon the expiration of each vessel's existing charter. These charters prevent the recognition of a sale of these vessels to Energos, and as such, proceeds associated with these 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 did not enter into a charter agreement to leaseback the Nanook , which was sold to Energos as part of the Energos Formation Transaction. After closing this transaction, we no longer recognize revenue from the sales-type lease of the Nanook and the related operating services agreement. 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- 28 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 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 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 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. 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 the third quarter of 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 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 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 this FLNG unit to Altamira in the third quarter of 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 29 Table of Contents 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 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. 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 by the end of 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. 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. Recent Developments On March 15, 2023, we completed a transaction with Golar LNG Limited (“GLNG”) for the sale of the Company's investment in the common units of Hilli LLC in exchange for approximately 4.1 million NFE shares and $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. Upon completion of the Hilli Exchange, we recognized an additional loss on disposal of $37.4 million, which was included in Other expense (income), 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. 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 commences, which is expected in the third quarter of 2023. In the first and second quarters of 2023, we entered into agreements with Weston Solutions, Inc. 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 expect to commission 350MW of duel-fuel power generation using our gas supply in the second quarter of 2023. In February 2023, our senior secured revolving credit facility (the "Revolving Facility") 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 30 Table of Contents 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 the Federal Energy Regulatory Commission ("FERC"), which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021, FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021; the FERC order was affirmed by the United States Court of Appeals for the District of Columbia Circuit on June 14, 2022. In order to comply with the FERC’s directive, on September 15, 2021, we filed an application for authorization to operate the San Juan Facility, which remains pending. Results of Operations – Three Months Ended March 31, 2023 compared to Three Months Ended December 31, 2022 and Three Months Ended March 31, 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 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. 31 Table of Contents The tables below present our segment information for the three months ended March 31, 2023, December 31, 2022 and March 31, 2022: Three Months Ended March 31, 2023 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 502,608 $ 97,917 $ 600,525 $ (21,394) $ 579,131 Cost of sales (1)(2) 73,798 — 73,798 111,140 184,938 Vessel operating expenses (4) — 19,239 19,239 (5,948) 13,291 Operations and maintenance (4) 26,671 — 26,671 — 26,671 Segment Operating Margin $ 402,139 $ 78,678 $ 480,817 $ (126,586) $ 354,231 Three Months Ended March 31, 2023 (in thousands of $) Consolidated Gross margin (GAAP) $ 319,856 Depreciation and amortization 34,375 Consolidated Segment Operating Margin (Non-GAAP) $ 354,231 Three Months Ended December 31, 2022 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 457,324 $ 106,990 $ 564,314 $ (17,945) $ 546,369 Cost of sales (2) 232,436 — 232,436 (96,537) 135,899 Vessel operating expenses (4) — 19,515 19,515 (6,729) 12,786 Operations and maintenance (4) 28,931 — 28,931 — 28,931 Segment Operating Margin $ 195,957 $ 87,475 $ 283,432 $ 85,321 $ 368,753 Three Months Ended December 31, 2022 (in thousands of $) Consolidated Gross margin (GAAP) $ 332,552 Depreciation and amortization 36,201 Consolidated Segment Operating Margin (Non-GAAP) $ 368,753 32 Table of Contents Three Months Ended March 31, 2022 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other (3) Consolidated Total revenues $ 480,349 $ 114,942 $ 595,291 $ (90,173) $ 505,118 Cost of sales (2) 235,532 — 235,532 (27,234) 208,298 Vessel operating expenses (4) 3,492 25,942 29,434 (6,470) 22,964 Operations and maintenance (4) 30,242 — 30,242 (7,074) 23,168 Segment Operating Margin $ 211,083 $ 89,000 $ 300,083 $ (49,395) $ 250,688 Three Months Ended March 31, 2022 (in thousands of $) Consolidated Gross margin (GAAP) $ 216,398 Depreciation and amortization 34,290 Consolidated Segment Operating Margin (Non-GAAP) $ 250,688 (1) Cost of sales in our segment measure only includes realized gains and losses on derivative transactions that are economic hedges of our commodity purchases and sales, and in the first quarter of 2023, realized gains of $146.1 million were recognized as a reduction to Cost of sales in the segment measure. For the three months ended March 31, 2023, December 31, 2022 and March 31, 2022, unrealized changes in the mark-to-market value of derivative transactions of $111.1 million, $96.4 million and $2.5 million, respectively, reconcile Cost of sales in the segment measure to Cost of sales in our condensed consolidated statements of operations and comprehensive income. (2) Cost of sales is presented exclusive of costs included in Depreciation and amortization in the condensed consolidated statements of operations and comprehensive income. (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, and exclusion of the unrealized mark-to-market gain or loss on derivative instruments. (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 $) March 31, 2023 December 31, 2022 Change March 31, 2022 Change Total revenues $ 502,608 $ 457,324 $ 45,284 $ 480,349 $ 22,259 Cost of sales (exclusive of depreciation and amortization) 73,798 232,436 (158,638) 235,532 (161,734) Vessel operating expenses — — — 3,492 (3,492) Operations and maintenance 26,671 28,931 (2,260) 30,242 (3,571) Segment Operating Margin $ 402,139 $ 195,957 $ 206,182 $ 211,083 $ 191,056 Total revenue Total revenue for the Terminals and Infrastructure Segment increased by $45.3 million for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022, and total revenue for the Terminals and 33 Table of Contents Infrastructure Segment increased by $22.3 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. The increases were primarily driven by increased revenue from LNG cargo sales to third parties and volumes delivered to our downstream terminal customers, partially offset by decreases to the Henry Hub index that forms a portion of the pricing to invoice most of our customers in this segment. The increase in revenue in the first quarter of 2023 when compared to the fourth quarter of 2022 was primarily attributable to the following: • Revenue from cargo sales was $349.4 million for the three months ended March 31, 2023, of which $169.5 million was recognized for a cancellation fee received from a customer to cancel a future delivery, increasing from $231.1 million for the three months ended December 31, 2022. • Volumes delivered to downstream terminal customers increased from 11.0 TBtus in the fourth quarter of 2022 to 12.1 TBtu in the first quarter of 2023, primarily as a result of increased consumption by the San Juan Power Plant, which was under maintenance for a portion of the fourth quarter of 2022. • The average Henry Hub index pricing used to invoice our downstream customers decreased by 45% for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022. The increase in revenue in the first quarter of 2023 when compared to the first quarter of 2022 was primarily attributable to the following: • Revenue from cargos sales was $349.4 million for the three months ended March 31, 2023 of which $169.5 million was recognized for a cancellation fee received from a customer to cancel a future delivery, as compared to $285.2 million for the three months ended March 31, 2022. • For the three months ended March 31, 2023, volumes delivered to downstream customers were 12.1 TBtu as compared to 6.3 TBtu for the three months ended March 31, 2022. During the first quarter of 2022, no volumes were consumed by the Bogue Power Plant due to the Port of Montego Bay where our facility resides requiring a reconfiguration and partial relocation of our assets. Additionally, maintenance activities lowered consumption at both our CHP Plant and the San Juan Power Plant in the first quarter of 2022; these facilities were not impacted by significant maintenance downtime in the current quarter. • The average Henry Hub index pricing used to invoice our downstream customers decreased by 31% for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. Additionally, 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. Our share of revenue from CELSEPAR was $63.4 million for the three months ended March 31, 2022, which was primarily comprised of fixed capacity payments received under related PPAs. 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 $158.6 million for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022, which was attributable to the following: • We settled a commodity swap transaction, entered into as an economic hedge to reduce market risks associated with commodity prices, in the first quarter of 2023 and the realized gain of $146.1 million was included as reduction of cost of sales. For segment performance measures, unrealized mark to market gains and losses are excluded until settled. In the fourth quarter of 2022, we recognized realized gains on commodity swap transactions of $36.5 million as a reduction to cost of sales. • Decreased cost of LNG purchased from third parties for sale to our downstream customers of $43.5 million. Volumes delivered to our downstream customers increased by approximately 10% in the current quarter; however, 34 Table of Contents our cost to deliver these volumes decreased significantly to $7.23 per MMBtu for the three months ended March 31, 2023 from $10.95 per MMBtu for the three months ended December 31, 2022. Cost of sales decreased by $161.7 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022, which was attributable to the following: • Realized gain of $146.1 million from the settlement of a commodity swap transaction, entered into as an economic hedge to reduce the market risks associated with commodity prices, was included as reduction of cost of sales in the first quarter of 2023. For segment performance measures, unrealized mark to market gains and losses are excluded until settled. We had no settlements of commodity derivative transactions in the first quarter of 2022. • We incurred increased cost of LNG purchased from third parties for sale to our downstream customers of $21.4 million in the first quarter of 2023 due to increased volumes delivered; we delivered 92% more volumes to our downstream terminal customers in the current period as compared to the three months ended March 31, 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 $7.23 per MMBtu for the three months ended March 31, 2023 from $9.49 per MMBtu for the three months ended March 31, 2022. • Cost of sales for the three months ended March 31, 2022 included $24.7 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. The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2023 and December 31, 2022 was $10.45 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 three months ended March 31, 2022, we incurred $3.5 million of vessel operating expenses in this segment; we did not incur vessel operating costs in this segment during the three months ended March 31, 2023 and 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 $2.3 million for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022. The decrease was primarily attributable to unplanned maintenance costs incurred in the fourth quarter of 2022 at the CHP Plant that did not recur in the first quarter of 2023. Operations and maintenance decreased $3.6 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022 . The decrease was due to the inclusion of our share of Operations and maintenance from our investment in CELSEPAR of $7.1 million for the three months ended March 31, 2022. There is no such activity in the first quarter of 2023 as we sold our investment in CELESPAR in the fourth quarter of 2022. The decrease was partially offset by additional vessel operating costs included in Operations and maintenance as these vessels support our terminal operations. Ships Segment Three Months Ended, (in thousands of $) March 31, 2023 December 31, 2022 Change March 31, 2022 Change Total revenues $ 97,917 $ 106,990 $ (9,073) $ 114,942 $ (17,025) Vessel operating expenses 19,239 19,515 (276) 25,942 (6,703) Segment Operating Margin $ 78,678 $ 87,475 $ (8,797) $ 89,000 $ (10,322) 35 Table of Contents 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. During the first quarter of 2023, four FSRUs and four LNG carriers were leased to customers under long-term or spot arrangements. 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 decreased $9.1 million for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022. 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. We plan to utilize these vessels in our operations following conversion and other upgrades starting later in 2023. Total revenue for the Ships segment decreased $17.0 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. The decrease in revenue was primarily the result of the sale of the Nanook as part of the Energos Formation Transaction; we recognized revenue of $13.2 million related to the Nanook in the first quarter of 2022. 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. 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 for the three months ended March 31, 2023 were consistent with those incurred in the three months ended December 31, 2022. Vessel operating expenses decreased $6.7 million for the three months ended March 31, 2023 as compared to the three months ended March 31, 2022. We incurred lower vessel operating costs due to vessels that are currently not under charter and are not in service due to drydocking or to complete other improvements to the vessels. Certain of our LNGCs are being converted to operate as an FSRU or FSU or are currently out of service for other improvements to service future projects. 36 Table of Contents Other operating results Three Months Ended, (in thousands of $) March 31, 2023 December 31, 2022 Change March 31, 2022 Change Selling, general and administrative $ 52,138 $ 70,099 $ (17,961) $ 48,041 $ 4,097 Transaction and integration costs 494 9,409 (8,915) 1,901 (1,407) Depreciation and amortization 34,375 36,201 (1,826) 34,290 85 Asset impairment expense — 2,550 (2,550) — — Total operating expenses 87,007 118,259 (31,252) 84,232 2,775 Operating income 267,224 250,494 16,730 166,456 100,768 Interest expense 71,673 80,517 (8,844) 44,916 26,757 Other expense (income), net 25,005 (16,431) 41,436 (19,725) 44,730 Income before income from equity method investments and income taxes 170,546 186,408 (15,862) 141,265 29,281 Income (loss) from equity method investments 9,980 (117,793) 127,773 50,235 (40,255) Tax provision (benefit) 28,960 2,810 26,150 (49,681) 78,641 Net income $ 151,566 $ 65,805 $ 85,761 $ 241,181 $ (89,615) 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 $18.0 million for the three months ended March 31, 2023, compared to the three months ended December 31, 2022. The decrease was primarily attributable to a decrease in share-based compensation expense. In the fourth quarter of 2022, we determined that the performance metric associated with our performance share units granted in 2021 was probable of vesting, and we recognized $15.8 million of share-based compensation expense. No share-based compensation expense was recognized in the first quarter of 2023. We also incurred lower screening costs in the first quarter of 2023 compared to the fourth quarter of 2022. Selling, general and administrative increased by $4.1 million for three months ended March 31, 2023 as compared to the three months ended March 31, 2022; the increase was primarily due to increased payroll costs associated with the continued expansion of our operations. Transaction and integration costs For the three months ended March 31, 2023, we incurred $0.5 million for transaction and integration costs, as compared to $9.4 million for the three months ended December 31, 2022 and $1.9 million for the three months ended March 31, 2022. During the three months ended December 31, 2022, we incurred costs associated with the sale of our investment in CELSEPAR. Transaction and integration costs incurred in the first quarter of 2022 were primarily associated with our continued integrations of acquisitions completed in 2021. Depreciation and amortization Depreciation and amortization was relatively consistent for the each of the three months ended March 31, 2023, December 31, 2022 and March 31, 2022. Throughout 2022 and the first quarter of 2023 we have not placed significant assets into service, and as such, our depreciation and amortization expense has been consistent. Asset impairment expense 37 Table of Contents We recognized long-lived assets associated with the expansion of the Sergipe Power Plant owned by CELSEPAR. In connection with the sale of our investment in CELSEPAR in the fourth quarter of 2022, we recognized asset impairment expense of $2.6 million. We did not recognize any impairment expense in the first quarter of 2023. Interest expense Interest expense decreased by $8.8 million for the three months ended March 31, 2023 as compared to the three months ended December 31, 2022. The decrease was primarily due to increases in capitalized interest, partially offset by increased interest expense due to borrowings under our expanded Revolving Credit Facility . Interest expense increased by $26.8 million for the three months ended March 31, 2023, as compared to the three months ended March 31, 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, under which we incur higher borrowing costs. The total principal balance on outstanding facilities was $5.3 billion as of March 31, 2023 as compared to total outstanding debt of $4.0 billion as of March 31, 2022. Other expense (income), net Other expense (income), net was $25.0 million, $(16.4) million and $(19.7) million for the three months ended March 31, 2023, December 31, 2022 and March 31, 2022, respectively. Other expense recognized in the three months ended March 31, 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, foreign currency remeasurment gains and gains on investments in equity securities. 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. Income recognized in the three months ended March 31, 2022 was primarily comprised of changes in the fair value of derivatives of $21.6 million. Tax provision We recognized a tax provision for the three months ended March 31, 2023 of $29.0 million compared to a tax provision of $2.8 million for the three months ended December 31, 2022 and a tax benefit of $49.7 million for the three months ended March 31, 2022. The significant tax benefit recognized in the first quarter of 2022 was primarily driven by significant discrete items, including the remeasurement of a deferred tax liability in conjunction with an internal reorganization. We have not recognized any significant discrete items in the first quarter of 2023. Income (loss) from equity method investments We recognized income from our equity method investments of $10.0 million and loss of $117.8 million for the three months ended March 31, 2023 and December 31, 2022, respectively. We recognized income of $4.0 million from our equity method investment in Energos in the three months ended March 31, 2023 and $6.0 million of income from our investment in Hilli for the period prior to the completion of the Hilli Exchange. 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. We recognized income of $50.2 million from our equity method investments in the three months ended March 31, 2022. Our share of earnings from CELSEPAR included a significant foreign currency remeasurement gain of $42.5 million. CELSEPAR was not included in our results of operations following the sale of this investment in 2022. 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 38 Table of Contents 98% of our LNG volumes from third parties for the three months ended March 31, 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 in the third quarter of 2023. • Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the three months ended March 31, 2023 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 our operations in Mexico. We have executed short-form agreements to extend and amend 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 these projects. Our current results also exclude other developments, including the Barcarena Facility, Santa Catarina Facility and Ireland Facility. • 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. 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 historically funded our developments through proceeds from our IPO, debt and equity financing, asset sales and cash from operations, and these financing transactions have been described in detail in our Annual Report. We have assumed total committed expenditures for all completed and existing projects to be approximately $4,414 million, with approximately $3,152 million having already been spent through March 31, 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 $800 million and $1 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 March 31, 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 39 Table of Contents paid during the first quarter of 2023. Additionally, we declared and paid quarterly dividends totaling $20.8 million during the three months ended March 31, 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. 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 March 31, 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 $ 7,468,642 $ 163,554 $ 2,757,933 $ 2,015,021 $ 2,532,134 Purchase obligations 13,847,969 1,501,951 1,458,028 1,278,496 9,609,494 Lease obligations 608,453 104,970 211,620 106,866 184,997 Total $ 21,925,064 $ 1,770,475 $ 4,427,581 $ 3,400,383 $ 12,326,625 Long-term debt obligations For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt” in our Annual Report. The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of March 31, 2023. A portion of debt service will be paid to Energos under charters of vessels included in the Energos Formation Transaction to third parties. The residual value of these vessels also forms a part of the obligation and will be recognized as a bullet payment at the end of the charters. As neither these third party charter payments nor the residual value of these vessels represent cash payments due by NFE, such amounts have been excluded from the table above. Purchase obligations We are party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. Certain LNG purchase commitments are subject to conditions precedent, and we include these expected commitments in the table above beginning when delivery is expected assuming that all contractual conditions precedent are met. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of March 31, 2023. We have construction purchase commitments in connection with our development projects, including the 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. 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, gas turbines and a land lease. 40 Table of Contents Cash Flows The following table summarizes the changes to our cash flows for the three months ended March 31, 2023 and 2022, respectively : Three Months Ended March 31, (in thousands of $) 2023 2022 Change Cash flows from: Operating activities $ 200,140 $ 114,382 $ 85,758 Investing activities (463,268) (189,221) (274,047) Financing activities 43,221 36,836 6,385 Net decrease in cash, cash equivalents, and restricted cash $ (219,907) $ (38,003) $ (181,904) Cash provided by operating activities Our cash flow provided by operating activities was $200.1 million for the three months ended March 31, 2023, which increased by $85.8 million from cash provided by operating activities of $114.4 million for the three months ended March 31, 2022. Our net income for the three months ended March 31, 2023, when adjusted for non-cash items, increased by $36.1 million from the three months ended March 31, 2022. The remaining increase for the first quarter of 2023 was driven by changes in working capital accounts. Cash used in investing activities Our cash flow used in investing activities was $463.3 million for the three months ended March 31, 2023, which increased by $274.0 million from cash used in investing activities of $189.2 million for the three months ended March 31, 2022. Cash outflows for investing activities during the three months ended March 31, 2023 were used primarily for continued development of our Fast LNG project. Cash outflows were offset by proceeds of $100.0 million from the sale of our equity method investment in Hilli LLC in the Hilli Exchange. Cash outflows for investing activities during the three months ended March 31, 2022 were used for continued development of our Fast LNG project, Santa Catarina Facility, Barcarena Facility, as well as expenditures to complete our La Paz Facility and Puerto Sandino Facility. Cash provided by financing activities Our cash flow provided by financing activities was $43.2 million for the three months ended March 31, 2023, which increased by $6.4 million from cash provided by financing activities of $36.8 million for the three months ended March 31, 2022. In December 2023, 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. Throughout the first quarter of 2023 we borrowed under our expanded Revolving Facility for total additional borrowings of $700.0 million, with such borrowings primarily used to fund the ongoing development of our Fast LNG project. Cash provided by financing activities during the three months ended March 31, 2022 was primarily due to proceeds from issuance of debt of $200.8 million, offset by repayments of debt of $123.7 million and payment of dividends of $23.8 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. Revolving Facility In February 2023, we entered into an amendment of our Revolving Facility which increased the commitments by $301.7 million, for a total capacity of $741.7 million. The interest rate for borrowings under the Revolving Facility based 41 Table of Contents on the current usage of the facility has not changed, and no changes were made to the maturity date or covenants. In conjunction with the amendment, we incurred an additional $5.0 million in fees which have been capitalized within Other non-current assets. Debt and lease restrictions The Company is 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. The Company was in compliance with all covenants as of March 31, 2023. Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report. As of March 31, 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.