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, 2021 (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 thousands. Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to our conversion from a limited liability company to a corporation, New Fortress Energy LLC and its subsidiaries and (ii) following the conversion from a limited liability company to a corporation, New Fortress Energy Inc. and its subsidiaries. Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to the completion of Mergers, New Fortress Energy Inc. and its subsidiaries, excluding Hygo Energy Transition Ltd. (“Hygo”) and its subsidiaries and Golar LNG Partners LP (“GMLP”) and its subsidiaries, and (ii) after completion of the Mergers, New Fortress Energy Inc. and its subsidiaries, including Hygo and its subsidiaries and GMLP and its subsidiaries. Overview We are a global energy infrastructure company founded to help address energy poverty and accelerate the world’s transition to reliable, affordable, and clean energy. We own and operate natural gas and liquefied natural gas ("LNG") infrastructure, and an integrated fleet of ships and logistics assets to rapidly deliver turnkey energy solutions to global markets. 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 carbon emission-free independent power providing companies. We discuss this important goal in more detail in our Annual Report, “Items 1 and 2: Business and Properties” under “Sustainability—Toward a Carbon-Free Future.” On April 15, 2021, we completed the acquisitions of Hygo and GMLP; referred to as the “Hygo Merger” and “GMLP Merger,” respectively and, collectively, the “Mergers.” As a result of the Hygo Merger, the Company acquired a 50% interest in a 1.5GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”) and its operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), as well as a terminal and power plant under development in the State of Pará, Brazil (the “Barcarena Facility” and "Barcarena Power Plant," respectively), a terminal under development on the southern coast of Brazil (the “Santa Catarina Facility”) and the Nanook, a newbuild FSRU moored and in service at the Sergipe Facility. As a result of the Mergers, we acquired a fleet of six other FSRUs, six LNG carriers and an interest in a floating liquefaction vessel, the Hilli Episeyo (the “Hilli”), each of which are expected to help support our existing facilities and international project pipeline. Acquired FSRUs are operating in Brazil, Indonesia and Jordan under time charters, and uncontracted vessels are available for short term employment in the spot market. Subsequent to the completion of the Mergers, 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. Leased vessels as well as the cost to operate our vessels that are utilized in our terminal or logistics operations are included in this segment. 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 35 Table of Contents acquired and leased fleet. The Terminals and Infrastructure segment includes all terminal operations in Jamaica, Puerto Rico, Mexico and Brazil, including our interest in the Sergipe Power Plant. Our Ships segment includes all vessels acquired in the Mergers, which are leased to customers under long-term or spot arrangements, including the 25-year charter of Nanook with CELSE. The Company’s investment in Hilli LLC, owner and operator of the Hilli , 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 in Jamaica and Puerto Rico, 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, and the Puerto Rico Electric Power Authority (“PREPA”), 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. We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our liquefaction facility in Dade County, Florida ("Miami Facility"). Our long-term goal is to develop the infrastructure necessary to supply our existing and future customers with LNG produced primarily at our own facilities, including Fast LNG and our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”) in addition to supplying our customers through long-term LNG contracts. 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. 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 PPA. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay SSA. In March 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. In August 2020, we began to deliver gas 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. We have delivered natural gas to PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020. Sergipe Power Plant and Sergipe Facility As part of the Hygo Merger, we acquired a 50% interest in Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), which owns Centrais Elétricas de Sergipe S.A. ("CELSE"), the owner and operator of the Sergipe Power Plant. The Sergipe Power Plant, a 1.5GW combined cycle power plant, receives natural gas from the Sergipe Facility through a dedicated 8-kilometer pipeline. The Sergipe Power Plant is one of the largest natural gas-fired thermal power stations in Latin America and was built to provide electricity on demand throughout the Brazilian electric integrated system, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the country. CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant is delivering power to 26 committed offtakers (utilities) for a period of 25 years. In any period in which power is not being produced pursuant to the PPAs, we are able to sell merchant power into the electricity grid at spot prices, subject to local regulatory approval. 36 Table of Contents We also own expansion rights with respect to the Sergipe Power Plant, which are owned by Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), a joint venture with Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A. , of which we own 75%. These rights include 190 acres of land and regulatory permits for two new power generation projects of 2.0GW in the aggregate. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. The Sergipe Facility is capable of processing up to 790,000 MMBtu per day and storing up to 170,000 cubic meters of LNG and supplies approximately 230,000 MMBtu per day (30% of the Sergipe Facility’s maximum regasification capacity) of natural gas to the Sergipe Power Plant, at full dispatch. 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 Current Operations – Ships Our Ships segment includes six FSRUs and five LNGCs, which are leased to customers under long-term or spot arrangements, including a 25-year charter of Nanook with CELSE. As these charter arrangements expire, we expect to use these vessels in our terminal operations and reflect such vessels in our Terminals and Infrastructure segment. We began to use one acquired LNGC in our terminal operations in the third quarter of 2021, and the results of operations of this vessel are no longer included in the Ships segment. The Company’s investment in Hilli LLC, owner and operator of the Hilli , is also included in the Ships segment. Hilli Corp, a wholly owned subsidiary of Hilli LLC, has a Liquefication Tolling Agreement (“LTA”) with Perenco Cameroon S.A. and Société Nationale des Hydrocarbures under which the Hilli provides liquefaction services through July 2026. Under the LTA, Hilli Corp receives a monthly tolling fee, consisting of a fixed element of hire and incremental tolling fees based on the price of Brent crude oil. Our Development Projects 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 of power supplied by gas-fired modular power units (the “La Paz Power Plant”) following the start of operations. Natural gas supply to the La Paz Power Plant may be increased to approximately 29,000 MMBtu of LNG per day for up to 135MW of power. 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 (the “Puerto Sandino Facility”). We have entered into a 25-year PPA with Nicaragua’s electricity distribution companies, and we expect to utilize approximately 57,500 MMBtu of LNG per day to provide natural gas to the Puerto Sandino Power Plant in connection with the 25-year power purchase agreement. Barcarena Facility The Barcarena Facility will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility will be 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 a new 605MW combined cycle thermal power plant to be located in Pará, Brazil (the “Barcarena Power Plant”), which is supported by multiple 25-year power purchase agreement 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. 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 MMBtu per day and LNG storage capacity of up to 170,000 cubic meters. 37 Table of Contents We are also 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 Garuva. The Santa Catarina Facility and associated pipeline are expected to have a total addressable market of 15 million cubic meters per day. Suape Facility We are developing our LNG terminal in the State of Pernambuco, Brazil (the “Suape Facility”). We intend for the Suape Facility to supply LNG to a 288MW thermoelectric power plant to also be located in the State of Pernambuco, Brazil (the “Suape Power Plant”). With the purchase of CH4 Energia Ltda. on January 12, 2021, we have obtained certain key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape. We also own certain 15-year power purchase agreements totaling 288MW for the development of two thermoelectric power plants, in the State of Bahia, Brazil, following the acquisition of 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energética Camaçari Muricy II S.A. (“Muricy”) on March 11, 2021. As of January 2022, we had commenced power sales under these power purchase agreements via forward selling agreements. We are seeking to obtain the necessary approvals from ANEEL and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Suape Facility and to update the technical characteristics to develop and construct an initial 288MW gas-fired power plant and LNG import terminal at the Port of Suape. Sri Lanka Facility We plan to develop an offshore LNG receiving, storage and regasification terminal to supply the Kerawalapitya Power Complex, in Colombo, Sri Lanka, where 310 MW of power is operational today and an additional 700 MW is scheduled to be built. We expect to initially provide the equivalent of an estimated 35,000 MMBtu of LNG per day, with the expectation of significant growth as new power plants become operational. Ireland Facility We intend to develop and operate an LNG facility (the “Ireland 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, and we intend to begin construction of the Ireland Facility after we have obtained the necessary consents and secured contracts with downstream customers with volumes sufficient to support the development. Fast LNG We are currently developing a series of modular floating liquefaction facilities to provide a source of low-cost supply of liquefied natural gas for our growing customer base. The “Fast LNG” design pairs advancements in modular, midsize liquefaction technology with jack up rigs, semi-submersible rigs or similar marine floating infrastructure to enable a much lower cost and faster deployment schedule than today’s floating liquefaction vessels. Semi-permanently moored FSU(s) will serve as LNG storage alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas. Other Projects We are 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 pricing or margins. Recent Developments Cargo Sales Since August 2021, LNG prices have increased materially, and global events, such as Russia’s invasion of Ukraine, have generated further energy pricing volatility. We have supply commitments to secure LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. Due to this significant increase in market pricing of LNG, we have optimized our supply portfolio to sell a portion of these cargos in the market, and these sales have positively impacted our results for the first quarter of 2022. Cargo sales of 9.7 TBtus were completed in the first quarter of 2022, increasing our revenues and results of operations for the three months ended March 31, 2022. COVID-19 Pandemic 38 Table of Contents We continue to closely monitor the impact of the novel coronavirus (“COVID-19”) pandemic on all aspects of our operations and development projects, including our marine operations acquired in the Mergers. Customers in our Terminals and Infrastructure segment primarily operate under long-term contracts, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We continue to invoice our customers for fixed minimum volumes even in cases when our customer’s consumption has decreased. We have not changed our payment terms with these customers, and there has not been deterioration in the timing or volume of collections. Many of the vessels acquired in the Mergers operate under long-term contracts with fixed payments. We are required to have adequate crewing aboard our vessels to fulfill the obligations under our contracts, and we have implemented safety measures to ensure that we have healthy qualified officers and crew. We monitor local or international transport or quarantine restrictions limiting the ability to transfer crew members off vessels or bring a new crew on board, and restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives, and we have not experienced significant disruptions in our operations due to these measures or restrictions. Based on the essential nature of the services we provide to support power generation facilities, our operations and development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We remain committed to prioritizing the health and well-being of our employees, customers, suppliers and other partners. We have implemented policies to screen employees, contractors, and vendors for COVID-19 symptoms upon entering our development projects, operations and office facilities. From the beginning of 2020 to March 31, 2022, we have incurred approximately $2.2 million to date for safety measures introduced into our operations and other responses to the COVID-19 pandemic. We are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread. We have not experienced significant disruptions in development projects, charter or terminal operations from the COVID-19 pandemic; however, there are important uncertainties including the scope, severity and duration of the pandemic, the actions taken to contain the pandemic or mitigate its impact, and the direct and indirect economic effects of the pandemic and containment measures. We do not currently expect these factors to have a significant impact on our results of operations, liquidity or financial position, or our development budgets or timelines. Other Matters On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, which was September 15, 2021, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, sought rehearing of the March 19, 2021 FERC order, and FERC denied all requests for rehearing in an order issued on July 15, 2021. We have filed petitions for review of FERC’s March 19 and July 15 orders with the United States Court of the Appeals for the District of Columbia Circuit. No other party has sought review of FERC’s orders. While our petitions for review are pending, and 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. 39 Table of Contents Results of Operations – Three Months Ended March 31, 2022 compared to Three Months Ended December 31, 2021 and Three Months Ended March 31, 2021 Segment performance is evaluated based on operating margin and the tables below present our segment information for the three months ended March 31, 2022, December 31, 2021 and March 31, 2021: Three Months Ended March 31, 2022 (in thousands of $) Terminals and Infrastructure (1) Ships (2) Total Segment Consolidation and Other (3) Consolidated Total revenues 480,349 114,942 595,291 (90,173) 505,118 Cost of sales 235,532 — 235,532 (27,234) 208,298 Vessel operating expenses 3,492 25,942 29,434 (6,470) 22,964 Operations and maintenance 30,242 — 30,242 (7,074) 23,168 Segment Operating Margin 211,083 89,000 300,083 (49,395) 250,688 Three Months Ended December 31, 2021 (in thousands of $) Terminals and Infrastructure (1) Ships (2) Total Segment Consolidation and Other (3) Consolidated Total revenues $ 689,770 $ 117,796 $ 807,566 $ (158,935) $ 648,631 Cost of sales 382,816 — 382,816 (100,339) 282,477 Vessel operating expenses 3,442 23,000 26,442 (5,466) 20,976 Operations and maintenance 25,158 — 25,158 (6,802) 18,356 Segment Operating Margin $ 278,354 $ 94,796 $ 373,150 $ (46,328) $ 326,822 Three Months Ended March 31, 2021 (in thousands of $) Terminals and Infrastructure Ships Total Segment Consolidation and Other Consolidated Total revenues $ 145,684 $ — $ 145,684 $ — $ 145,684 Cost of sales 96,671 — 96,671 — 96,671 Vessel operating expenses — — — — — Operations and maintenance 16,252 — 16,252 — 16,252 Segment Operating Margin $ 32,761 $ — $ 32,761 $ — $ 32,761 (1) Terminals and Infrastructure includes our effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR. The earnings and losses attributable to the investment of $36,680 and $18,580 for the three months ended March 31, 2022 and December 31, 2021, respectively, are reported in income (loss) from equity method investments in the consolidated statements of operations and comprehensive income (loss). Terminals and Infrastructure does not include the unrealized mark-to-market gain and loss on derivative instruments of $2,492 and $472 for the three months ended March 31, 2022 and December 31, 2021, respectively, reported in Cost of sales. (2) Ships includes our effective share of revenues, expenses and operating margin attributable to 50% ownership of the Hilli Common Units. The earnings attributable to the investment of $13,555 and $10,065 for the three months ended March 31, 2022 and December 31, 2021, respectively, are reported in income (loss) from equity method investments in the consolidated statements of operations and comprehensive income (loss). (3) Consolidation and Other adjust for the inclusion of our effective share of revenues, expenses and operating margin attributable to 50% ownership of CELSEPAR and Hilli Common Units in our segment measure and exclusion of the unrealized mark-to-market gain or loss on derivative instruments. 40 Table of Contents Terminals and Infrastructure Segment Three Months Ended, (in thousands of $) March 31, 2022 December 31, 2021 Change March 31, 2021 Change Total revenues $ 480,349 $ 689,770 $ (209,421) $ 145,684 $ 334,665 Cost of sales 235,532 382,816 (147,284) 96,671 138,861 Vessel operating expenses 3,492 3,442 50 — 3,492 Operations and maintenance 30,242 25,158 5,084 16,252 13,990 Segment Operating Margin $ 211,083 $ 278,354 $ (67,271) $ 32,761 $ 178,322 Total revenue Total revenue for the Terminals and Infrastructure Segment decreased $209,421 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. The decrease was primarily driven by lower revenue from LNG cargo sales to third parties. Revenue from cargo sales was $285,171 for the three months ended March 31, 2022 and $422,880 for the three months ended December 31, 2021. Our revenue was also negatively impacted by decreases to the Henry Hub index in the first quarter. Our contracts with customers in this segment typically include a portion of pricing based on the Henry Hub index, and the average Henry Hub index pricing used to invoice our customers decreased by 15% for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. Total revenue for the Terminals and Infrastructure Segment increased $334,665 for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021. We recognized revenue for LNG cargos sold to third parties and our share of revenue from our investment in CELSEPAR during the first quarter of 2022, totaling $348,560. We did not have any cargo sales transactions in the first quarter of 2021, and the acquisition of our investment in CELSEPAR in the Mergers occurred subsequent to March 31, 2021. Accordingly, the increased revenue was primarily driven by these transactions. The following table summarizes the volumes delivered, exclusive of LNG cargo volumes sold to third parties, in the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and the three months ended March 31, 2021: Three Months Ended (in TBtu) March 31, 2022 December 31, 2021 Change March 31, 2021 Change Old Harbour Facility 3.0 3.2 (0.2) 4.4 (1.4) Montego Bay Facility 0.5 1.0 (0.5) 2.0 (1.5) San Juan Facility 1.1 1.1 — 4.0 (2.9) Other 1.7 1.2 0.5 0.3 1.4 Total volumes delivered in the current period 6.3 6.5 (0.2) 10.7 (4.4) A summary of the impact to revenue from our operations at our Old Harbour Facility is as follows: • Sales at the Old Harbour Facility decreased by $4,888 from $62,491 for the three months ended December 31, 2021 to $57,603 for the three months ended March 31, 2022. The decrease in revenue from the Old Harbour Facility was due to revenue deferred for volumes delivered below the take-or-pay minimums in our contracts and a decrease in the Henry Hub index used to invoice our customers as compared to the three months ended December 31, 2021. • Sales at the Old Harbour Facility increased by $6,065 from $51,538 for the three months ended March 31, 2021 to $57,603 for the three months ended March 31, 2022. The increase in revenue from the Old Harbour Facility was due to an increase in the Henry Hub index used to invoice our customers as compared to the three months ended March 31, 2021, which was partially offset by a decrease in volumes delivered at the Old Harbour Power Plant. 41 Table of Contents • The Jamalco refinery experienced a fire in August 2021, and no gas volumes have been consumed by their boilers since this event. Revenue from the delivery of power and steam from the CHP Plant decreased by $5,713 and $5,591 from the three months ended December 31, 2021 and March 31, 2021, respectively, to $1,651 for the three months ended March 31, 2022. Revenue was also impacted by operations at our Montego Bay Facility. • During the first quarter of 2022, no volumes were consumed by the Bogue Power Plant, leading to the significant decrease in volumes delivered at the Montego Bay Facility, due to the port authority at the Port of Montego Bay where our facility resides requiring a reconfiguration and partial relocation of our assets. We expect this reconfiguration to be completed in the second quarter of 2022, and at that time, we will recommence deliveries to the Bogue Power Plant. • As no volumes were delivered to the Bogue Power Plant, our revenue from the Montego Bay Facility decreased by $7,417 from $18,129 for the three months ended December 31, 2021 to $10,712 for the three months ended March 31, 2022. Similarly, sales at the Montego Bay Facility decreased by $14,067 from $24,779 for the three months ended March 31, 2021 to $10,712 for the three months ended March 31, 2022. The San Juan Power Plant completed additional maintenance activities in the first quarter of 2022, leading to lower consumption of natural gas. Sales at the San Juan Facility decreased by $3,959 from $14,953 for the three months ended December 31, 2021 to $10,994 for the three months ended March 31, 2022. Sales at the San Juan Facility also decreased by $34,624 for the three months ended March 31, 2022. Revenue from cargo sales was $285,171 for the three months ended March 31, 2022 as compared to $422,880 for the three months ended December 31, 2021. For the three months ended March 31, 2021, we did not have any cargo sale transactions in the first quarter of 2021. Subsequent to the acquisition of our interest in the Sergipe Facility as part of the Mergers, our share of revenue from our investment in CELSEPAR was $63,389 for the three months ended March 31, 2022 and $132,876 for the three months ended December 31, 2021, which was primarily comprised of fixed capacity payments received under CELSE's PPAs. Revenue recognized from the operation of the Sergipe Power Plant was significantly increased in the fourth quarter of 2021 by emergency dispatch due to poor hydrological conditions in Brazil. As hydrology conditions have improved in the first quarter of 2022, the Sergipe Power Plant has been dispatched less, reducing revenue from our share of our investment in CELSEPAR 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 $147,284 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. • The decrease was primarily due to lower cost and volume of LNG cargo sales in the market. We recognized $86,462 during the three months ended March 31, 2022 to acquire cargos sold to third parties, as compared to $166,027 for the three months ended December 31, 2021. Due to the significant increase in market pricing of LNG in the second half of 2021 and continued increase in the first quarter of 2022, we have optimized our supply portfolio to sell a portion of our committed cargos in the market. LNG cargo sales in the market decreased by 6.6 TBtus from 16.3 TBtus for the three months ended December 31, 2021 to 9.7 TBtus for the three months ended March 31, 2022. The weighted-average cost of LNG from the sale of a portion of our cargos also decreased from $10.20 per MMBtu for the three months ended December 31, 2021 to $8.81 per MMBtu for the three months ended March 31, 2022. • During the first quarter of 2022, the Sergipe Power Plant was dispatched substantially less than in the fourth quarter of 2021 due to improved hydrology conditions in Brazil. Our share of cost of sales from our investment in CELSEPAR, which was primarily comprised of LNG costs to fuel the power plant, was $24,742 for the three months ended March 31, 2022, as compared to $100,811 for the three months ended December 31, 2021 • Cost of LNG purchased from third parties for sale to our customers decreased $6,633 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. The decrease was primarily 42 Table of Contents attributable to a 3% decrease in volumes delivered compared to the three months ended December 31, 2021, and a slight decrease in LNG cost. The weighted-average cost of LNG purchased from third parties decreased from $9.57 per MMBtu for the three months ended December 31, 2021 to $9.49 per MMBtu for the three months ended March 31, 2022. Cost of sales increased $138,861 for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021. • We recognized cost to acquire LNG cargos sold to third parties and our share of cost of sales from our investment in CELSEPAR during the first quarter of 2022, totaling $111,204. We did not have any cargo sale transactions in the first quarter of 2021, and the acquisition of our investment in CELSEPAR in the Mergers occurred subsequent to March 31, 2021. Accordingly, the increased costs of sales was primarily driven by these transactions. • Cost of LNG purchased from third parties for sale to our customers decreased $5,017 for the three months ended March 31, 2022 as compared to the three months ended March 31, 2021. We delivered 41% less volumes to our terminal customers in the current quarter as compared to the three months ended March 31, 2021. Our cost of LNG was significantly higher in the current quarter, and as such, the decrease of cost of sales to deliver to our terminal customers did not fully correspond with the decrease in volumes. The weighted-average cost of LNG purchased from third parties increased from $6.17 per MMBtu for the three months ended March 31, 2021 to $9.49 per MMBtu for the three months ended March 31, 2022. The weighted-average cost of our LNG inventory balance to be used in our operations as of March 31, 2022 and December 31, 2021 was $8.21 per MMBtu and $9.51 per MMBtu, respectively. Operations and maintenance Operations and maintenance includes costs of operating our facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance increased $5,084 and $13,990 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and March 31, 2021, respectively . • The increase for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021 and March 31, 2021 was primarily attributable to higher logistics costs associated with our ISO container distribution system. In the first quarter of 2022, we continued to source LNG from our Miami Facility to service industrial end users in Jamaica due to the reconfiguration and partial relocation of our assets at the Port of Montego Bay, and we incurred additional costs to distribute LNG to customers via our ISO container distribution system. • Additionally, the increased costs in the first quarter of 2022 when compared to the first quarter of 2021 was due to the inclusion of our share of Operations and maintenance from our investment in CELSEPAR of $7,074 for the three months ended March 31, 2022, which was primarily comprised of costs related to the operation and services agreement for the Nanook , insurance costs and costs for connecting to the transmission system. Ships Segment Three Months Ended, (in thousands of $) March 31, 2022 December 31, 2021 Change March 31, 2021 Change Total revenues 114,942 $ 117,796 $ (2,854) $ — $ 114,942 Cost of sales — — — — — Vessel operating expenses 25,942 23,000 2,942 — 25,942 Operations and maintenance — — — — — Segment Operating Margin $ 89,000 $ 94,796 $ (5,796) $ — $ 89,000 Prior to the completion of the Mergers, we reported our results of operations in a single segment; all the assets and operations that comprise the Ships segment were acquired in the Mergers, and as such, there are no results of operations prior to the completion of the Mergers during the second quarter of 2021. 43 Table of Contents Revenue in the Ships segment is comprised of operating lease revenue under time charters, fees for repositioning vessels as well as the reimbursement of certain vessel operating costs. We have 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 include the interest income earned under sales-type leases as revenue as amounts earned under chartering and operating service agreements represent our ongoing ordinary business operations. At the completion of the Mergers, five of the FSRUs and two LNGCs were on hire under long-term charter agreements, and one LNGCs, the Grand , was operating in the spot market. In the third quarter, the Grand , began to be utilized in our terminal and logistics operations, and as such, the results of operations of the Grand are included in the Terminals and Infrastructure segment from the third quarter of 2021 onward. The Spirit and the Mazo continue to be in cold lay-up, and no vessel charter revenue was generated from these vessels. Total revenue Total revenue for the Ships segment decreased $2,854 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. The decrease was primarily driven by lower revenue as a result of a change in on-hire days quarter over quarter. The calendar quarter is two days shorter in the first quarter, and as such, revenue decreased slightly due to lower number of commercial on-hire days. Vessel operating expenses Vessel operating expenses include direct costs associated with operating a vessel, such as crewing, repairs and maintenance, insurance, stores, lube oils, communication expenses, management fees and costs to operate the Hilli . We also recognize voyage expenses within Vessel operating expenses, which principally consist of fuel consumed before or after the term of time charter or when the vessel is off hire. Under time charters, the majority of voyage expenses are paid by customers. To the extent that these costs are a fixed amount specified in the charter, which is not dependent upon redelivery location, the estimated voyage expenses are recognized over the term of the time charter. Vessel operating expenses increased $2,942 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021, primarily due to increased customs claims in Jordan where one of our FSRUs operates. As all operations of the Ships segment were acquired in the Mergers, there were no comparable transactions for the three months ended March 31, 2021. Other operating results Three Months Ended, (in thousands of $) March 31, 2022 December 31, 2021 Change March 31, 2021 Change Selling, general and administrative $ 48,041 $ 74,927 $ (26,886) $ 33,617 $ 14,424 Transaction and integration costs 1,901 2,107 (206) 11,564 (9,663) Depreciation and amortization 34,290 30,297 3,993 9,890 24,400 Total operating expenses 84,232 107,331 (23,099) 55,071 29,161 Operating income (loss) 166,456 219,491 (53,035) (22,310) 188,766 Interest expense 44,916 46,567 (1,651) 18,680 26,236 Other (income), net (19,725) (3,692) (16,033) (604) (19,121) Loss on extinguishment of debt, net — 10,975 (10,975) — — Net income (loss) before income from equity method investments and income taxes 141,265 165,641 (24,376) (40,386) 181,651 Income (loss) from equity method investments 50,235 (8,515) 58,750 — 50,235 Tax (benefit) provision (49,681) 5,403 (55,084) (877) (48,804) Net income (loss) $ 241,181 $ 151,723 $ 89,458 $ (39,509) $ 280,690 Selling, general and administrative 44 Table of Contents Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors and screening costs associated with development activities for projects that are in initial stages and development is not yet probable. Selling, general and administrative decreased $26,886 for the three months ended March 31, 2022, as compared to the three months ended December 31, 2021. The decrease was primarily attributable to a decrease in share-based compensation expense. In the fourth quarter of 2021, due to the significant impact of cargo sales on our results of operations, we determined that the performance metric associated with our performance share units granted in 2020 was probable of vesting, and we recognized $30,467 of share-based compensation expense. We also have incurred higher payroll costs, insurance expenses, management fees and professional fees due to the continue expansion of our operations as compared to the fourth quarter of 2021. Selling, general and administrative increased $14,424 for the three months ended March 31, 2022, as compared to the three months ended March 31, 2021. The increase was primarily attributable to higher payroll, professional fees and managements fees associated with the continued expansion of our operations. Transaction and integration costs For the three months ended March 31, 2022, we incurred $1,901 for transaction and integration costs, as compared to $2,107 and $11,564 for the three months ended December 31, 2021 and March 31, 2021, respectively. For the three months ended March 31, 2021, we incurred transaction and integration costs were incurred in connection with the Mergers, which consisted primarily of financial advisory, legal, accounting and consulting costs. Our integration costs decreased in both the fourth quarter of 2021 and the first quarter of 2022 as the integration of GMLP and Hygo has progressed since the acquisition date. Depreciation and amortization Depreciation and amortization increased $3,993 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. For the three months ended March 31, 2022, we incurred higher amortization of favorable and unfavorable contracts acquired in the Mergers as the amortization of certain unfavorable contract liabilities (reduction to expense) was completed in the fourth quarter of 2021. Depreciation and amortization increased $24,400 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. The increase was primarily due to the following: • Subsequent to the completion of the Mergers, our results of operations include depreciation expense primarily for the vessels acquired. We recognized $14,070 of incremental depreciation expense for the acquired vessels during the three months ended March 31, 2022 • Amortization of the value recorded for favorable and unfavorable contracts acquired in the Mergers of $8,346 for the three months ended March 31, 2022. Interest expense Interest expense decreased by $1,651 for the three months ended March 31, 2022 as compared to the three months ended December 31, 2021. The decrease was primarily due to the termination of the sale leaseback agreement of the Eskimo assumed in the Mergers. Interest expense increased by $26,236 for the three months ended March 31, 2022, as compared to the three months ended March 31, 2021. The increase was primarily due to an increase in total principal outstanding due to the issuance of the 2026 Notes in April 2021, draws on the Revolving Facility, borrowings under the Vessel Term Loan Facility and the South Power 2029 Bonds (all defined in our Annual Report); principal balance on outstanding facilities was $3,978,250 as of March 31, 2022 as compared to total outstanding debt of $1,250,000 as of March 31, 2021. In conjunction with the Mergers, we assumed outstanding debentures issued by a subsidiary of Hygo and the outstanding debt of variable interest entities (“VIEs”) that are now consolidated in our financial statements, totaling $389,946 as of December 31, 2021. Although we have no control over the funding arrangements of these entities, we are the primary beneficiary of these VIEs and therefore these loan facilities are presented as part of the condensed consolidated financial statements. For the three months ended March 31, 2022, we recognized additional interest expense attributable to assumed debt of $3,378. 45 Table of Contents Other (income) expense, net Other (income) expense, net increased by $16,033 and $19,121 for the three months ended March 31, 2022, as compared to the three months ended December 31, 2021 and March 31, 2021, respectively. Income recognized in the first quarter of 2022 was primarily comprised of the following : • Changes in the fair value of the cross-currency interest rate swap and the interest rate swaps acquired in connection with the Mergers, resulted in income of $24,409 for the three months ended March 31, 2022. • Changes in the fair value adjustments for the equity agreement and derivatives related to contingent payments due to sellers in asset acquisitions resulted in additional expense of $2,765 for the three months ended March 31, 2022. Loss on extinguishment of debt, net Loss on extinguishment of debt for the three months ended December 31, 2021 was $10,975. In November 2021, we exercised our option to terminate the sale leaseback agreement of the Eskimo assumed in the Mergers in exchange for a total payment of $190,518. The counterparty to this sale leaseback arrangement (“Eskimo SPV”) had been consolidated in our financial statements subsequent to the Mergers. In connection with the termination of this financing arrangement, we recognized a loss on extinguishment of debt based on the difference between the repurchase price under the sale leaseback arrangement and the carrying value of the net assets of the Eskimo SPV upon deconsolidation. There were no comparable transactions for the three months ended March 31, 2022 or March 31, 2021. Tax provision We recognized a tax benefit for the three months ended March 31, 2022 of $49,681 compared to a tax provision of $5,403 for the three months ended December 31, 2021 and a tax benefit of $877 for the three months ended March 31, 2021. The increase to the tax benefit and associated decrease to the effective tax rate for the three months ended March 31, 2022 was primarily driven by the remeasurement of a deferred income tax liability in conjunction with an internal reorganization. Our equity method investment in CELSEPAR is now directly held by a subsidiary domiciled in the United Kingdom; the investment was previously held by a subsidiary domiciled in Brazil resulting in a discrete tax benefit of $76,460 recognized in the first quarter of 2022. This increase in benefit for the three months ended March 31, 2022 was partially offset by an increase in pretax income for certain profitable operations, including GMLP and Hygo, for the three months ended March 31, 2022. The Company has not recorded any material changes in liabilities for uncertain tax positions as of March 31, 2022. Income from equity method investments We recognized income (loss) from our investments in Hilli and CELSEPAR of $50,235 for the three months ended March 31, 2022 and $(8,515) for the three months ended December 31, 2021, respectively. Our share of earnings from CELSEPAR was significantly impacted by a foreign currency remeasurement gain of $42,466, net of applicable statutory rate for the three months ended March 31, 2022 as a result of the remeasurement of the Nanook finance lease obligation, as compared to a remeasurement loss of $(6,788), net of applicable statutory rate for the three months ended December 31, 2021. 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 include the results of operations of Hygo and GMLP only since the completion of the Mergers in April 2021. Upon completion of the Mergers, we acquired a fleet of seven FSRUs, six LNG carriers and an interest in a floating liquefaction vessel. We also acquired a 50% interest in the Sergipe Facility and the Sergipe Power Plant, as well as the Barcarena Facility and Barcarena Power Plant and the Santa Catarina Facility that are currently in development. The results of operations of Hygo and GMLP began to be included in our financial statements upon the closing of the acquisitions on April 15, 2021. Our results of operations after the acquisitions also included transaction and integration costs associated with these acquisitions, some of which would not be expected in future periods. Our future results of operations may continue to be impacted by costs to integrate the operations of Hygo and GMLP, including 46 Table of Contents costs to exit or modify transition service agreements or vessel management agreements, all of which may be significant. • 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, 2022 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We recently placed a portion of our La Paz Facility into service, and in the fourth quarter of 2021, our revenue and results of operations began to be impacted by operations in Mexico. We are continuing to develop of our La Paz Power Plant and 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 Suape Facility, Barcarena Facility, Santa Catarina Facility and Ireland Facility. • Our historical financial results do not reflect new LNG supply agreements, as well as 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 94% of our LNG volumes from third parties for the three months ended March 31, 2022. We have entered into LNG supply agreements at a price indexed to Henry Hub through 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement. We have entered into supply agreements to secure supply of LNG volumes equal to approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years; pricing under these agreements is indexed to Henry Hub, resulting in expected pricing below our historical supply agreements. We also 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. Since August 2021, LNG prices have increased materially. Due to this significant increase in market pricing of LNG, we have optimized our supply portfolio to sell a portion of our committed cargos in the market with delivery throughout 2022, and these cargo sales are expected to increase our 2022 revenues and 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. We expect to fund our current operations and continued development of additional facilities through cash on hand, borrowings under our debt facilities and cash generated from operations. We may also opportunistically elect to generate additional liquidity through future debt or equity issuances and asset sales to fund developments and transactions. We have historically funded our developments through proceeds from our IPO and debt and equity financing, most recently as follow s (below terms defined in our Annual Report): • In September 2020, we issued $1,000,000 of 2025 Notes and repaid all other outstanding debt. No principal payments are due on the 2025 Notes until maturity in 2025. • In December 2020, we received proceeds of $263,125 from the issuance of $250,000 of additional notes on the same terms as the 2025 Notes (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). • In December 2020, we issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs. • In April 2021, we issued $1,500,000 of 2026 Notes; we also entered into the $200,000 Revolving Facility that has a term of approximately five years; in February 2022, we expanded capacity under the Revolving Facility to $315,000. • In August 2021, we entered into the CHP Facility and initially drew $100,000, which may be increased to $285,000. In January 2022, we agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. Through the first quarter of 2022, we have received proceeds of $175,783 from the issuance of South Power 2029 Bonds. 47 Table of Contents • In September 2021, Golar Partners Operating LLC, our indirect subsidiary, closed on the Vessel Term Loan Facility. Under this facility, we borrowed an initial amount of $430,000, which may be increased to $725,000, subject to satisfaction of certain conditions including the provision of security in relation to additional vessels. We have assumed total committed expenditures for all completed and existing projects to be approximately $2,080 million, with approximately $1,584 million having already been spent through March 31, 2022. This estimate represents the committed expenditures for our Fast LNG project, as well as committed expenditures necessary to complete the La Paz Facility, Puerto Sandino Facility, the Suape Facility, the Barcarena Facility, Santa Catarina Facility and the Sri Lanka Facility. We expect to be able to fund all such committed projects with a combination of cash on hand, cash flows from operations and proceeds from the South Power 2029 Bonds (defined below). We may also enter into other financing arrangements to generate proceeds to fund our developments. As of March 31, 2022, we have spent approximately $128 million to develop the Pennsylvania Facility. Approximately $22 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 million, has been capitalized, and to date, we have repurposed approximately $17 million of engineering and equipment to our Fast LNG project. Our current air permit required to construct the Pennsylvania Facility is expected to expire in July 2022. We intend to apply for an updated air permit for the Pennsylvania Facility with the aim of obtaining this permit to coincide with the commencement of construction activities. Contractual Obligations We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2021. There were no material changes to our contractual obligations in the first quarter 2022. (in thousands) Total Year 1 Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 4,936,353 $ 305,575 $ 878,471 $ 3,341,677 $ 410,630 Purchase obligations 5,265,356 784,060 1,637,783 1,450,817 1,392,696 Lease obligations 420,329 67,131 101,295 68,393 183,510 Total $ 10,622,038 $ 1,156,766 $ 2,617,549 $ 4,860,887 $ 1,986,836 Long-term debt obligations For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2021. 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. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of December 31, 2021. We have secured supply of LNG for approximately 100% of our expected needs for our Montego Bay Facility, Old Harbour Facility, San Juan Facility, La Paz Facility and Puerto Sandino Facility for the next six years. We have construction purchase commitments in connection with our development projects, including the La Paz Facility, Puerto Sandino Facility, Suape Facility, Barcarena Facility, Santa Catarina Facility, as well as our Fast LNG solution. 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 48 Table of Contents short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease. As of December 31, 2021, the Company had seven vessels under time charter leases with remaining non-cancellable terms ranging from one month to ten years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services. The Company has executed a lease for an LNG carrier that has not commenced as of December 31, 2021, which has a noncancelable terms of seven years and includes fixed payments of approximately $198,100; these payments are not included in the table above. We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 20 to 25 years. The land site lease is held with an affiliate of the Company and has a remaining term of approximately five years with an automatic renewal term of five years for up to an additional 20 years. During 2020, we executed multiple lease agreements for the use of ISO tanks, and we began to receive these ISO tanks and the lease terms commenced during the second quarter of 2021. The lease term for each of these leases is five years and expected payments under these lease agreements have been included in the above table. Office space includes space shared with affiliated companies in New York, as well as offices in Miami, New Orleans, and Rio de Janeiro, which have lease terms between three to seven years. Cash Flows The following table summarizes the changes to our cash flows for the three months ended March 30, 2022 and March 31, 2021, respectively : Three Months Ended March 31, (in thousands) 2022 2021 Change Cash flows from: Operating activities $ 114,382 $ (111,986) $ 226,368 Investing activities (189,221) (90,257) (98,964) Financing activities 36,836 (47,891) 84,727 Net (decrease) in cash, cash equivalents, and restricted cash $ (38,003) $ (250,134) $ 212,131 Cash provided by operating activities Our cash flow provided by operating activities was $114,382 for the three months ended March 31, 2022, which increased by $226,368 from cash used in operating activities of $111,896 for the three months ended March 31, 2021. Our net income for the three months ended March 31, 2022, when adjusted for non-cash items, increased by $180,828 from the three months ended March 31, 2021. Changes in working capital accounts, primarily increases in accounts payable and accrued liabilities, also contributed to additional cash provided by operating activities. Cash used in investing activities Our cash flow used in investing activities was $189,221 for the three months ended March 31, 2022, which increased by $98,964 from cash used in investing activities of $90,257 for the three months ended March 31, 2021. Cash outflows for investing activities during the three months ended March 31, 2022 were also used for continued development of our Fast LNG solution, Santa Catarina Facility, Barcarena Facility, as well as expenditures to complete our La Paz Facility and Puerto Sandino Facility. Cash outflows for investing activities during the three months ended March 31, 2021 were primarily used for development projects in Nicaragua and Mexico. Cash provided by financing activities Our cash flow provided by financing activities was $36,836 for the three months ended March 31, 2022, which increased by $84,727 from cash used in financing activities of $47,891 for the three months ended March 31, 2021. Cash provided by financing activities during the three months ended March 31, 2022 was due to proceeds from issuance of debt of $200,836, offset by repayments of debt of $123,669 and payment of dividends of $23,773. 49 Table of Contents Cash flow used in financing activities during the three months ended March 31, 2021 was due to payments of $29,564 related to tax withholdings for share-based compensation, as well as dividends paid of $17,657. 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. South Power 2029 Bonds In August 2021, NFE South Power Holdings Limited (“South Power”), a wholly owned subsidiary of NFE, entered into a financing agreement (“CHP Facility”), initially receiving approximately $100,000. The CHP Facility was secured by a mortgage over the lease of the site on which our CHP Plant is located and related security. In January 2022, South Power and the counterparty to the CHP Facility agreed to rescind the CHP Facility and entered into an agreement for the issuance of secured bonds (“South Power 2029 Bonds”) and subsequently authorized the issuance of up to $285,000 in South Power 2029 Bonds. The South Power 2029 Bonds are secured by, amongst other things, the CHP Plant. Amounts outstanding at the time of the mutual rescission of the CHP Facility of $100,000 were credited towards the purchase price of the South Power 2029 Bonds. In the first quarter of 2022, South Power issued $75,783 of South Power 2029 Bonds for a total amount outstanding of 175,783 as of March 31, 2022. The South Power 2029 Bonds bear interest at an annual fixed rate of 6.50% and mature seven years from the closing date of the final tranche. No principal payments will be due until 2025. We expect that beginning in May 2025, principal payments will be due on a quarterly basis. Interest payments on outstanding principal balances will be due quarterly. Principal payments and interest payments on the South Power 2029 Bonds are guaranteed by NFE. South Power will be required to comply with certain financial covenants as well as customary affirmative and negative covenants. The South Power 2029 Bonds also provides for customary events of default, prepayment and cure provisions. In conjunction with obtaining the CHP Facility, we incurred $3,243 in origination, structuring and other fees. The rescission of the CHP Facility and issuance of South Power 2029 Bonds was treated as a modification, and fees attributable to lenders that participated in the CHP Facility will be amortized over the life of the South Power 2029 Bonds; additional fees associated with such lenders of $258,000 were recognized as expense in the first quarter of 2022. Additional fees for new lenders participating in the South Power 2029 Bonds were recognized as a reduction of the principal balance on the condensed consolidated balance sheets. As of March 31, 2022 and December 31, 2021, the remaining unamortized deferred financing costs for the CHP Facility was $5,527 and $3,180, respectively. Debt and lease restrictions The VIE loans and certain lease agreements with customers assumed in the Mergers contain certain operating and financing restrictions and covenants that require: (a) certain subsidiaries to maintain a minimum level of liquidity of $30,000 and consolidated net worth of $123,950, (b) certain subsidiaries to maintain a minimum debt service coverage ratio of 1.20:1, (c) certain subsidiaries to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (d) certain subsidiaries to maintain a minimum percentage of the vessel values over the relevant outstanding loan facility balances of either 110% and 120%, (e) certain subsidiaries to maintain a ratio of liabilities to total assets of less than 0.70:1. As of March 31, 2022, the Company was in compliance with all covenants under debt and lease agreements. Financial covenants under GMLP's Vessel Term Loan Facility include requirements that GMLP and the borrowing subsidiary maintain a certain amount of Free Liquid Assets, that the EBITDA to Consolidated Debt Service and the Net Debt to EBITDA ratios are no less than 1.15:1 and no greater than 6.50:1, respectively, and that Consolidated Net Worth is greater than $250 million, each as defined in the Vessel Term Loan Facility. GMLP was in compliance with these covenants as of March 31, 2022 . The Company is also 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, 2022. 50 Table of Contents Debt obligations of equity method investees We account for the investments in CELSEPAR and Hilli LLC acquired in the Mergers under the equity method of accounting, and the debt obligations of these entities are not reported separately in our consolidated financial statements. The key terms of CELSEPAR's and Hilli LLC's debt obligations are summarized in our Annual Report. In July 2021, CELSE and CELSEPAR entered into a working capital facility for the posting of certain letters of credit in favor of the supplier of LNG and the financing of LNG costs to satisfy dispatch requirements prior to receiving related variable revenues. Standby letters of credit are guaranteed, jointly but not severally, by CELSE’s shareholders, NFE and Ebrasil. The working capital facility is in an aggregate amount of up to $200.0 million (or its equivalent in Reais). The facility has a term of 12 months, renewable for equal periods by mutual agreement of the parties. Amounts disbursed under the working capital facility accrue interest at a rate referenced to Libor+, and contractual margins. As of March 31, 2022, there were no standby letters of credit issued under this facility. Off Balance Sheet Arrangements As of March 31, 2022 and December 31, 2021, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results . Critical Accounting Policies and Estimates A complete discussion of our critical accounting policies and estimates is included in our Annual Report for the year ended December 31, 2021. There have been no significant changes in our critical accounting policies and estimates in the current year. 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.