New Fortress Energy Inc. 10-K

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Certain information contained in this discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis. The comparison of the years ended December 31, 2019 and 2018 can be found in our Annual Report on Form 10‑K for the year ended December 31, 2019 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with GAAP. This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in 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. When used in a historical context that is prior to the completion of NFE’s initial public offering (“IPO”), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Holdings LLC, a Delaware limited liability company (“New Fortress Energy Holdings”), our predecessor for financial reporting purposes. Overview We are a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs. We deliver targeted energy solutions to customers around the world, thereby reducing their energy costs and diversifying their energy resources, while also reducing pollution and generating compelling margins. 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 “Items 1 and 2: Business and Properties” under “Toward a Carbon-Free Future”. As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to 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. We expect that control of our vertical supply chain, from procurement to delivery of LNG, will help to reduce our exposure to future LNG price variations and enable us to supply our existing and future customers with LNG at a price that reinforces our competitive standing in the LNG market. Our strategy is simple: we seek to procure LNG at attractive prices using long-term agreements and through our own production, and we seek to sell natural gas (delivered through LNG infrastructure) or gas-fired power to customers that sign long-term, take-or-pay contracts. Our Current Operations 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 production 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 natural gas liquefaction and storage facility located in Miami-Dade County, Florida (the “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 our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”). 65 Table of Contents Montego Bay Facility Our storage and regasification terminal in Montego Bay, Jamaica (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 740,000 gallons of LNG (61,000 MMBtu) 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 Our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility”) commenced commercial operations in June 2019 and is capable of processing approximately six million gallons of LNG (500,000 MMBtu) per day. The Old Harbour Facility supplies natural gas to the new 190MW Old Harbour power plant (the “Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term power purchase agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay steam supply agreement. On March 3, 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 In July 2020, we finalized the development of the micro-fuel handling facility in the Port of San Juan, Puerto Rico (the “San Juan Facility”). The San Juan Facility is near the San Juan Power Plant and serves as our supply hub for the San Juan Power Plant and other industrial end-user customers in Puerto Rico. We have delivered natural gas used for the commissioning of PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020. Miami Facility Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) 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. Other Development Projects We are in the process of developing an LNG regasification facility and power plant at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). Initially, the La Paz Facility is expected to supply approximately 270,000 gallons of LNG (22,300 MMBtu) per day under an intercompany GSA for approximately 100 MW of power supplied by gas-fired modular power units that we plan to develop, own and operated, which may be increased to 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power. In addition, we were declared the winner of a bid with CFEnergia for the supply of natural gas to power plants located in Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day and are in the process of finalizing definitive agreements for this supply. We are also in the process of developing an LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”). In February 2020, we entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, and we are in the process of constructing an approximately 300 MW natural gas-fired power plant that will consume approximately 700,000 gallons of LNG (57,500 MMBtus) per day. Recent Developments: Hygo and GMLP Acquisitions Hygo Acquisition On January 13, 2021, NFE and Lobos Acquisition Ltd., a Bermuda exempted company and our wholly-owned subsidiary (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (the “Hygo Merger Agreement”) with Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), pursuant to which Hygo Merger Sub will merge with and into Hygo (the “Hygo Merger”), with Hygo surviving the Hygo Merger as a wholly owned subsidiary of NFE. As of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021. 66 Table of Contents The Hygo Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals and other customary closing conditions. Upon completion of the acquisition of Hygo, we expect to acquire one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Terminal”) a 50% interest in a 1.5 GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in development in Pará, Brazil (the “Barcarena Terminal”) and Santa Catarina, Brazil (the “Santa Catarina Terminal”). In addition, we expect to acquire Hygo’s vessel fleet, which consists of the Golar Nanook , a newbuild FSRU moored and in service at the Sergipe Terminal, and two operating LNG carriers, the Golar Celsius and the Golar Penguin , which may be converted into FSRUs. GMLP Acquisition On January 13, 2021, we entered into an Agreement and Plan of Merger (the “GMLP Merger Agreement) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability company and the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and an indirect subsidiary of NFE (“GMLP Merger Sub”), and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales and an indirect subsidiary of NFE (“GP Buyer”), pursuant to which GMLP Merger Sub will merge with and into GMLP, with GMLP surviving the merger as an indirect subsidiary of NFE (the “GMLP Merger”). At the effective time of the GMLP Merger (the “GMLP Effective Time”), each common unit representing a limited partner interest in GMLP that is issued and outstanding as of immediately prior to the GMLP Effective Time will automatically be converted into the right to receive $3.55 in cash. At the GMLP Effective Time, each of the incentive distribution rights of GMLP will be canceled and cease to exist, and no consideration shall be delivered in respect thereof. Each 8.75% Series A Cumulative Redeemable Preferred Unit of GMLP issued and outstanding immediately prior to the GMLP Effective Time will be unaffected by the GMLP Merger and will remain outstanding, and no consideration shall be delivered in respect thereof. Each outstanding unit representing a general partner interest of GMLP that is issued and outstanding immediately prior to the GMLP Effective Time will remain issued and outstanding immediately following the GMLP Effective Time. Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General Partner pursuant to a Transfer Agreement dated as of January 13, 2021 for a purchase price of approximately $5 million, which is equivalent to $3.55 per general partner unit of GMLP. The GMLP Merger Agreement may be terminated by NFE or GMLP (which, in the case of GMLP, must be approved by GMLP’s Conflicts Committee) under certain circumstances, including, among others, by either NFE or GMLP if the closing of the GMLP Merger has not occurred on or before July 13, 2021, and further provides that, upon termination of the GMLP Merger Agreement under certain circumstances, GMLP may be required to pay NFE a termination fee equal to approximately $9.4 million. The GMLP Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals, the approval of the GMLP Merger Agreement by the majority of the holders of GMLP common units and other customary closing conditions. Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel, the Hilli, which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, each of which are expected to help support our existing facilities and international project pipeline. The majority of the FSRUs in GMLP’s fleet are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters. GMLP’s uncontracted vessels are available for short term employment in the spot market. Suape Development On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape in the city of Ipojuca, State of Pernambuco, Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.(“ Pecém”) and Energética Camaçari Muricy II S.A (“Muricy”). These companies collectively hold certain 15-year power purchase agreements totaling 288 MW for the development of the thermoelectric power plants in the State of Bahia, Brazil. We will seek to obtain the necessary approvals from the Agência Nacional de Energia Elétrica (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics in order to develop and plan to construct a 288MW gas-fired power plant and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil. 67 Table of Contents COVID-19 Pandemic We are closely monitoring the impact of the novel coronavirus (“COVID-19”) pandemic on all aspects of our operations and development projects. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We have continued to invoice our customers for these 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. Based on the essential nature of the services we provide to support power generation facilities, our 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. For the year ended December 31, 2020, we have incurred approximately $1.2 million 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 and daily operations during the year ended December 31, 2020 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 We received an order from the Federal Energy Regulatory Commission (“FERC”) on June 18, 2020, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the Natural Gas Act. While 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. The matter was raised during a FERC open meeting held on January 19, 2021 but was not resolved , is on the agenda during the FERC open meeting to be held on March 18, 2021, and remains pending. We do not know if or when FERC will respond to our reply, or the outcome of any such response. 68 Table of Contents Results of Operations – Year Ended December 31, 2020 compared to Year Ended December 31, 2019 (in thousands) Year Ended December 31, 2020 2019 Change Revenues Operating revenue $ 318,311 $ 145,500 $ 172,811 Other revenue 133,339 43,625 89,714 Total revenues 451,650 189,125 262,525 Operating expenses Cost of sales 278,767 183,359 95,408 Operations and maintenance 47,581 26,899 20,682 Selling, general and administrative 124,170 152,922 (28,752 ) Contract termination charges and loss on mitigation sales 124,114 5,280 118,834 Depreciation and amortization 32,376 7,940 24,436 Total operating expenses 607,008 376,400 230,608 Operating loss (155,358 ) (187,275 ) 31,917 Interest expense 65,723 19,412 46,311 Other expense (income), net 5,005 (2,807 ) 7,812 Loss on extinguishment of debt, net 33,062 - 33,062 Loss before taxes (259,148 ) (203,880 ) (55,268 ) Tax expense 4,817 439 4,378 Net loss $ (263,965 ) $ (204,319 ) $ (59,646 ) Revenues Operating revenue from the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilities for the year ended December 31, 2020 was $318,311 which increased by $172,811 from $145,500 for the year ended December 31, 2019. The increase was primarily driven by volumes sold from the Old Harbour Terminal, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020: • For the year ended December 31, 2020, we recognized $189,196 of revenue from volumes sold at the Old Harbour Facility, as compared to $41,229 for the year ended December 31, 2019. Revenue recognized for the year ended December 31, 2020 included $112,334 from sales to the Old Harbour Power Plant and $76,862 from natural gas utilized in the CHP Plant and Jamalco’s boilers. For the year ended December 31, 2020, the volume delivered to the Old Harbour Power Plant was 96.0 million gallons (8.0 TBtu) and the volume utilized in the CHP Plant and Jamalco’s boilers was 96.2 million gallons (7.9 TBtu). For the year ended December 31, 2019, the volume delivered to the Old Harbour Power Plant was 22.2 million gallons (1.9 TBtu). • Additional revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco added $23,062 in revenue for the year ended December 31, 2020. Operating revenue was also impacted by operations at our Montego Bay Facility, including the following: • In connection with the adoption of ASC 842, we no longer identify a lease of the Montego Bay Facility in our gas sale agreement with our customer. Accordingly, interest income associated with the direct financing lease of the Montego Bay Facility is no longer recognized within Other revenue, and all amounts recognized as revenue for activities at the Montego Bay Facility were included in Operating revenue for the year ended December 31, 2020, resulting in an increase of $15,771 to Operating revenue. • The increase in Operating revenue is partially offset by a decrease in sales at the Montego Bay Facility. The decrease in sales at the Montego Bay Facility was primarily due to a decrease in sales volume delivered to the Bogue Power Plant. Revenue from sales at the Montego Bay Facility decreased $ 14,399 to $ 77,464 for the year ended December 31, 2020 as compared to $ 91,863 for the year ended December 31, 2019 . The delivered volume at the Montego Bay Facility decreased by 16.3 million gallons ( 1.2 TBtu) from 110.5 million gallons ( 9.1 TBtu) during the year ended December 31, 2019 to 94.2 million gallons ( 7.9 TBtu) during the year ended December 31, 2020 . 69 Table of Contents Other revenue includes revenue from development services, which is recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our power generation facilities, and such services are included within certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities. Other revenue increased $89,714 for the year ended December 31, 2020 as compared to the year ended December 31, 2019 , and the increases were due to the following: • Increase of $113,777 for development services in Puerto Rico for the year ended December 31, 2020, including conversion of the customer’s infrastructure within the San Juan Power Plant and gas used by our customer for testing and commissioning their assets. Development services revenue recognized in the year ended December 31, 2020 included $118,757 for the customer’s use of 129.5 million gallons (10.7 TBtu) of natural gas as part of commissioning their assets. • Lower revenue recognized for the infrastructure projects for customers of the CHP Plant. For the year ended December 31, 2020, we recognized $601 for the completion of infrastructure projects for customers of the CHP Plant, as compared to $11,933 for the year ended December 31, 2019. 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, power generation facilities or to our customers. 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 for the year ended December 31, 2020 was $278,767 which increased $95,408 from $183,359 for the year ended December 31, 2019. C ost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $92,433 for the year ended December 31, 2020 as compared to the year ended December 31, 2019. The increase was primarily attributable to the increase in volumes delivered of approximately 200% compared to the year ended December 31, 2019, partially offset by the decrease in LNG cost. The weighted-average cost of LNG purchased from third parties decreased from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020. The weighted-average cost of our inventory balance as of December 31, 2020 and 2019 was $0.40 per gallon ($4.81 per MMBtu) and $0.64 per gallon ($7.70 per MMBtu), respectively. Charter costs associated with our expanded fleet increased Cost of sales by $ 5,763 for the year ended December 31, 2020 . The increase was attributable to a full year of charter costs of the Old Harbour Facility in 2020 as well as additional costs associated with our San Juan Facility after the assets were placed in service in the third quarter of 2020 . The increase in Cost of sales was partially offset by a decrease in costs associated with the infrastructure projects for customers of the CHP Plant and conversion of our customer’s infrastructure within the San Juan Power Plant of $ 11,482 as compared to the year ended December 31, 2019 . 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 for the year ended December 31, 2020 was $47,581, which increased $20,682 from $26,899 for the year ended December 31, 2019. The increase is primarily a result of higher logistics costs of $ 9,727 for the year ended December 31, 2020 , primarily associated with the operations of additional charter vessels deployed. Operations and maintenance also increased by $ 5,425 for the year ended December 31, 2020 for costs of operating the CHP Plant for the period after commencement of commercial operations in March 2020 and by $ 5,698 for costs of operating the San Juan Facility after our assets were placed in service in the third quarter of 2020 . 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 costs associated with development activities for projects that are in initial stages and development is not yet probable. 70 Table of Contents Selling, general and administrative for the year ended December 31, 2020, was $124,170 which decreased $28,752 from $152,922 for the year ended December 31, 2019. The decrease was primarily attributable to decreased share-based compensation expense of $32,651, as well as decreases to professional fees of $3,743, as compared to the year ended December 31, 2019. These decreases were partially offset by $8,344 of higher payroll costs associated with increased headcount. Contract termination charges and loss on mitigation sales Contract termination charges and loss on mitigation sales for the years ended December 31, 2020 and 2019 was $124,114 and $5,280, respectively. Through 2020, the pricing of LNG in the open market was significantly lower than the pricing in our LNG supply agreement with Centrica. In June 2020, we executed an agreement to terminate our obligation to purchase LNG from Centrica for the remainder of 2020 in exchange for a payment of $105,000, and we recognized this cancellation charge during the second quarter of 2020. We terminated our obligation in the second quarter of 2020 to, among other reasons, take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs. We purchased LNG in the open market for the remainder of our needs in 2020, significantly reducing our LNG supply cost from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020. We experienced lower than expected consumption by some of our customers in the second quarter of 2020, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica. As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of $18,906 on the sale of this cargo that was recognized during the second quarter of 2020. Loss on mitigation sales for the year ended December 31, 2019 was $5,280 which was attributable to losses incurred associated with undelivered quantities of LNG under firm purchase commitments due to storage capacity constraints. Depreciation and amortization Depreciation and amortization for the year ended December 31, 2020 was $32,376, which increased $24,436 from $7,940 for the year ended December 31, 2019. The increase was primarily due to the following: • Increase in depreciation of $3,582 for our Old Harbour Facility that went into service in June 2019; • Increase in depreciation of $9,515 for the CHP Plant that went into service in March 2020; • Increase in depreciation of $4,484 for the San Juan Facility that went into service in July 2020; • Additional depreciation of $4,499 recognized on our Montego Bay Facility during the year. These assets were presented as direct financing leases prior to the adoption of ASC 842, and no depreciation for such assets was previously recorded. Interest expense Interest expense for the year ended December 31, 2020 was $65,723, which increased $46,311 from $19,412 for the year ended December 31, 2019, primarily as a result of the additional principal balances outstanding during 2020 under the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds, as compared to the Term Loan Facility (all defined below). When the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds were replaced by the Senior Secured Notes in September 2020, the outstanding principal balances totaled $980,000, as compared to the Term Loan Facility principal amount as of December 31, 2019 of $495,000, which had been extinguished in January 2020. As of December 31, 2020, we have issued $1,250,000 of Senior Secured Notes. Other expense (income), net Other expense (income), net for the year ended December 31, 2020 was $5,005, which increased $7,812 from income of ($2,807) for the year ended December 31, 2019, primarily as a result of the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG, a decrease in interest income, and an increase in unrealized loss on our investment in equity securities. Loss on extinguishment of debt, net Loss on extinguishment of debt was $33,062 for the year ended December 31, 2020 as a result of the extinguishment of the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds in September 2020, as well as the loss recognized upon the extinguishment of the Term Loan Facility in January 2020. Loss on extinguishment of debt for the year ended December 31, 2019 was $0 as we did not have any such transactions during the year. 71 Table of Contents Tax expense Tax expense for the year ended December 31, 2020 was $4,817, which increased $4,378 from a tax expense of $439 for the year ended December 31, 2019. During 2020, the CHP Plant began operations and we placed our assets at the San Juan Facility in service. Certain of our Jamaican operations had increased earnings for the year ended December 31, 2020 without any historical net operating losses to offset additional tax expense. We have recognized tax expense in Puerto Rico at a preferential tax rate due to our tax decree resulting in an effective tax rate lower than the U.S. federal income tax rate. We continue to have valuation allowances in many of our foreign jurisdictions and tax expense for earnings generated in many foreign jurisdictions has been limited. 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 include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2020 include our Montego Bay Facility, Miami Facility, sales from our Old Harbour Facility to SJPC, and certain industrial end-users. The CHP Plant commenced commercial operations during March 2020 , and our results now include revenue and results operations from sales of gas, power and steam from the CHP Plant. We also completed the development of our San Juan Facility in third quarter of 2020 , and in the second quarter of 2020 , we began to deliver natural gas to the San Juan Power Plant for PREPA to use in the commissioning of their assets. Our current results do not include revenue and operating results from other projects under development including the La Paz Facility, the Puerto Sandino Facility, or the Ireland Facility. • Our historical financial results do not reflect changes to our current long-term LNG supply agreement as well as new LNG supply agreements that will lower the cost of our LNG supply through 2030. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the year ended December 31, 2020 . In June 2020 , we entered into an agreement to terminate our obligation to purchase LNG from our supplier for the remainder of 2020 in exchange for a payment of $ 105,000 , and for the remainder of 2020 , we purchased all volumes needed for our operations on the open market, significantly reducing our LNG supply costs from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020 . During 2020, we also entered into four LNG supply agreements for the purchase of approximately 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement. • Our historical financial results do not include the anticipated acquisitions of Hygo and GMLP as well as transaction and integration costs expected to be incurred associated with these acquisitions. Upon completion of the acquisition of Hygo, we expect to acquire the Sergipe Terminal, a 50% interest in the Sergipe Power Plant, as well as the Barcarena Terminal and the Santa Catarina Terminal that are currently in development. In addition, we expect to acquire one FSRU in service at the Sergipe Terminal and two operating LNG carriers which may be converted into FSRUs. Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel. The results of operations of Hygo and GMLP will begin to be included in our financial statements upon the closing of the acquisitions, expected in the first half of 2021. Our results of operations in 2021 will also include transaction costs associated with these acquisitions as well as costs incurred to integrate the operations of Hygo and GMLP into our business. • We no longer qualify as an emerging growth company or “EGC”. As an EGC we were able to take advantage of an exemption from providing an auditor’s attestation on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes Oxley Act. Following the issuance of Senior Secured Notes in September 2020, we ceased to qualify as an EGC and can no longer take advantage of this exemption. We are also now required to accelerate the adoption of certain new or revised accounting pronouncements. Starting in 2020, we will incur additional costs associated with providing an auditor’s attestation report, adoption of accounting standards on an accelerated timeline, as well as additional audit costs resulting from PCAOB requirements . 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 and cash generated from operations. We may also elect to generate additional liquidity through future debt or equity issuances to fund developments and transactions. We have historically funded our developments through proceeds from our IPO and debt and equity financing as follows: 72 Table of Contents • Our IPO was completed on February 4, 2019, and we raised net proceeds of $268,010, inclusive of additional net proceeds raised from the exercise of the underwriter’s option to purchase additional shares and after deducting underwriting discounts and commissions and transaction costs. • In March 2019, we drew the remaining availability on our Term Loan Facility and had $495,000 of outstanding principal as of December 31, 2019. • In September 2019, we issued approximately $117,000 in Senior Secured Bonds and Senior Unsecured Bonds, and in December 2019, we issued an additional $63,000 in Senior Secured Bonds, which was fully funded by January 2020. • In January 2020, we borrowed $800,000 under the Credit Agreement and repaid the Term Loan Facility in full. • In September 2020, we issued $1,000,000 of Senior Secured Notes and repaid in full amounts due on the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds. No principal payments are due on the Senior Secured Notes until maturity in 2025. • In December 2020, we received proceeds of $263,500 from the issuance of $250,000 of additional notes on the same terms as the Senior Secured Notes (subsequent to this issuance, these additional notes are included in the definition of Senior Secured 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. We have assumed total expenditures for all completed and existing projects to be approximately $ 1,181 million , with approximately $ 789 million having already been spent through December 31, 2020 . This estimate represents the expenditures necessary to complete the La Paz Facility and the Puerto Sandino Facility, expected expenditures to serve new industrial end-users and other planned capital expenditures. We expect to be able to fund all such committed projects with a combination of cash on hand and cash flows from operations. Through December 31, 2020 , we have spent approximately $ 159 million to develop the Pennsylvania Facility. Approximately $ 20 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 $ 139 million , has been capitalized. We have obtained debt financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA for loans in an aggregate principal amount of $ 1.7 billion , consisting of a $ 1.5 billion senior secured bridge facility (the “Bridge Loan”) and a $ 200 million senior secured revolving facility to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If NFE utilizes the Bridge Loan, the facility will bear a fixed interest rate of 6.25% , subject to a step-up of 50 basis points every three months. The Bridge Loan has a one -year term, is pre-payable without penalty and will automatically be converted into a seven -year term loan if it is not repaid in full at maturity. The senior secured revolving facility has a term of approximately five years and bears interest based on the three -month LIBOR rate plus certain margins. 73 Table of Contents Cash Flows The following table summarizes the changes to our cash flows for the years ended December 31, 2020 and 2019, respectively: Year Ended December 31, (in thousands) 2020 2019 Change Cash flows from: Operating activities $ (125,566 ) $ (234,261 ) $ 108,695 Investing activities (157,631 ) (376,164 ) 218,533 Financing activities 819,498 602,607 216,891 Net increase (decrease ) in cash, cash equivalents, and restricted cash $ 536,301 $ (7,818 ) $ 544,119 Cash (used in) operating activities Our cash flow used in operating activities was $125,566 for the year ended December 31, 2020, which decreased by $108,695 from $234,261 for the year ended December 31, 2019. The reduction in cash flow used in operating activities for the year ended December 31, 2020 was due to more favorable changes in working capital accounts. Fluctuations in inventory balances led to an increase in operating cash flows of $23,230 for the year ended December 31, 2020 compared to a $50,345 decrease in operating cash flows for the year ended December 31, 2019. The impact of increasing accounts payable and accrued liabilities on cash flows from operations was $55,514 for the year ended December 31, 2020 compared to $3,036 for the year ended December 31, 2019. Cash (used in) investing activities Our cash flow used in investing activities was $157,631 for the year ended December 31, 2020, which decreased by $218,533 from $376,164 for the year ended December 31, 2019. Cash outflows for investing activities during the year ended December 31, 2020 were primarily used to complete the CHP Plant and the San Juan Facility, as well as construction of the La Paz Facility. Cash used in investing activities during the year ended December 31, 2019 significant capital expenditures for development of our Old Harbour Facility, CHP Plant, San Juan Facility and Pennsylvania Facility, as well as payments for significant outstanding amounts to our suppliers that were accrued as of December 31, 2018. Cash provided by financing activities Our cash flow provided by financing activities was $819,498 for the year ended December 31, 2020, which increased by $216,891 from $602,607 for the year ended December 31, 2019. Cash provided by financing activities during the year ended December 31, 2020 was due to proceeds received from the borrowings under the Senior Secured Notes of $1,250,000, the Credit Agreement of $800,000 and Senior Secured Bonds of $52,144. A portion of these proceeds from the Senior Secured Notes were used to fund the repayment of the Credit Agreement of $800,000, the Senior Secured Bonds and Senior Unsecured Bonds of $183,600 and the Term Loan Facility of $506,402. The proceeds received were further offset by transaction costs and other fees incurred to obtain the borrowings. In 2020, we also received proceeds from the issuance of Class A common stock of $291,922, offset by stock issuance costs of $1,107. Cash dividends of $33,742 were paid, partially offsetting financing inflows. Cash flow provided by financing activities during the year ended December 31, 2019 were primarily consisted of the issuance of Senior Secured Bonds and Senior Unsecured Bonds of $117,000 in September 2019, additional borrowings under the Term Loan Facility of $220,000 in March 2019 and proceeds received from our IPO of $274,948 in February 2019. Long-Term Debt Senior Secured Notes On September 2, 2020 , the Company issued $ 1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144 A under the Securities Act (the “Senior Secured Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021 ; no principal payments are due until maturity on September 15, 2025 . The Company may redeem the Senior Secured Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums. The Senior Secured Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The Senior Secured Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The Senior Secured Notes also provide for customary events of default and prepayment provisions. 74 Table of Contents We used a portion of the net cash proceeds received from the Senior Secured Notes to repay in full the outstanding principal and interest under the Credit Agreement, including related costs and expenses. We also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds, including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds. The redemption of the Senior Secured Bonds and Senior Unsecured Bonds was completed on September 21, 2020 . In connection with the issuance of the Senior Secured Notes, we incurred $ 17,937 in origination, structuring and other fees. Issuance costs of 13,909 were deferred as a reduction of the principal balance of the Senior Secured Notes on the consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the Senior Secured Notes were $ 6,501 and such unamortized costs were also included as a reduction of the principal balance of the Senior Secured Notes and will be amortized over the remaining term of the Senior Secured Notes. As a portion of the repayment of the Credit Agreement was a modification, we recorded $ 4,028 of third -party fees in Selling, general and administrative in the consolidated statements of operations and comprehensive loss. On December 17, 2020 , the Company issued $ 250,000 of additional notes on the same terms as the Senior Secured Notes in a private offering pursuant to Rule 144 A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of Senior Secured Notes herein). Proceeds received included a premium of $ 13,125 , which was offset by additional financing costs incurred of $ 4,188 . As of December 31, 2020 , total remaining unamortized deferred financing costs were $ 10,439 . The Credit Agreement On January 10, 2020, the Company entered into a credit agreement to borrow $800,000 in term loans (the “Credit Agreement”). The Credit Agreement was to mature in January 2023 with the full principal balance due upon maturity. Interest was payable quarterly and was based on a LIBOR rate divided by one minus the applicable reserve requirement, subject to a floor of 1.50%, plus a margin of 6.25%. The interest rate margin was to increase each year of the term by 1.50%. Outstanding balances could be prepaid at our option at any time without premium. We used a portion of the proceeds received to extinguish the Term Loan Facility. We were required to comply with certain financial covenants as well as usual and customary affirmative and negative covenants, including limitations on liens and incurring additional indebtedness. The facility also provided for customary events of default and cure provisions. In connection with obtaining the Credit Agreement and the extinguishment of the Term Loan Facility, the Company incurred $37,051 in origination, structuring and other fees which were recognized as a reduction of the principal balance of the Credit Agreement on the consolidated balance sheets. On September 2, 2020, we repaid the full amount outstanding using proceeds from the Senior Secured Notes. Certain holders of the Credit Agreement participated in the issuance of Senior Secured Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the Senior Secured Notes. Term Loan Facility On August 16, 2018, the Company entered into a credit agreement with a syndicate of two lenders to borrow up to an aggregate principal amount of $240,000. On December 31, 2018, the Company amended this credit agreement (as amended, the “Term Loan Facility”) to, among other things, (i) increase the amount available for borrowing thereunder from $240,000 to $500,000, (ii) extend the initial maturity date to December 31, 2019, (iii) modify certain provisions relating to restrictive covenants and existing financial covenants, and (iv) remove the mandatory prepayment required with the net proceeds received in connection with an IPO. As of December 31, 2018, the outstanding principal balance under the Term Loan Facility was $280,000. On March 21, 2019, the Company drew an additional $220,000, bringing our total outstanding borrowings to $500,000 under the Term Loan Facility, and as of December 31, 2019 , the total principal amount outstanding under the Term Loan Facility was $ 495,000 . All borrowings under the Term Loan Facility bore interest at a rate selected by us of either (i) LIBOR divided by one minus the applicable reserve requirement plus a spread of 4% or (ii) subject to a floor of 1%, a Base Rate equal to the higher of (a) the Prime Rate, (b) the Federal Funds Rate plus 1/2 of 1% or (c) the 1-month LIBOR rate plus 1.00% plus a spread of 3.0%. The Term Loan Facility was repayable in quarterly installments of $1,250 with a balloon payment due at maturity. 75 Table of Contents The Term Loan Facility was secured by mortgages on certain properties owned by our subsidiaries, in addition to other collateral. The Term Loan Facility was amended in the third quarter of 2019 to allow certain properties of a consolidated subsidiary to secure the Senior Secured Bonds. We were also required to comply with certain financial covenants and other restrictive covenants customary for facilities of this type, including restrictions on indebtedness, liens, acquisitions and investments, restricted payments and dispositions. We incurred costs in connection with obtaining the Term Loan Facility, the extinguishment of our prior debt facilities, and the amendment of the Term Loan Facility. Some of the costs incurred were capitalized as a reduction to the Term Loan Facility on the consolidated balance sheets, and all deferred financing costs associated with the Term Loan Facility were amortized over the term of the Term Loan Facility, through December 31, 2019. As such, there were no unamortized deferred financing costs as of December 31, 2019. The Term Loan Facility had a maturity date of December 31, 2019 with an option to extend the maturity date for two additional six-month periods. Upon the exercise of each extension option, we would pay a fee equal to 1.0% of the outstanding principal balance at the time of the exercise, and the spread on the LIBOR and Base Rate would increase by 0.5%. On December 30, 2019, the Company entered into an amendment with the lenders to extend the maturity to January 21, 2020. Prior to this new maturity date, on January 15, 2020, we repaid the full amount outstanding, using proceeds from the Credit Agreement to extinguish the Term Loan Facility. South Power Bonds On September 2, 2019, NFE South Power Holdings Limited (“South Power”), a consolidated subsidiary of the Company, entered into a facility for the issuance of secured and unsecured bonds (the “Senior Secured Bonds” and “Senior Unsecured Bonds”, respectively) and subsequently issued $73,317 and $43,683 in Senior Secured Bonds and Senior Unsecured Bonds, respectively. The Senior Secured Bonds are secured by the CHP Plant and related receivables and assets, and the proceeds will be used to fund the completion of the CHP Plant and to reimburse shareholder advances. In the fourth quarter of 2019, South Power issued an additional $63,000 in Senior Secured Bonds. We received $10,856 of the proceeds in 2019 and received the remaining proceeds of $52,144 in January 2020. The Senior Secured Bonds bore interest at an annual fixed rate of 8.25% and matured 15 years from the closing date of each issuance. No principal payments were due for the first seven years. Beginning in 2026, quarterly principal payments of approximately 1.6% of the original principal amount were due, with a 50% balloon payment due upon maturity. Interest payments on outstanding principal balances were due quarterly. The Senior Unsecured Bonds bore interest at an annual fixed rate of 11.00% and matured in September 2036. No principal payments were due for the first nine years. Beginning in 2028, principal payments were due quarterly on an escalating schedule. Interest payments on outstanding principal balances were due quarterly. South Power was required to comply with certain financial covenants as well as customary affirmative and negative covenants, including limitations on incurring additional indebtedness. The facility also provided for customary events of default, prepayment and cure provisions. The Company paid approximately $ 3,892 of fees in connection with the issuance of Senior Secured Bonds and Senior Unsecured Bonds. These fees were capitalized on a pro-rata basis as a reduction of the Senior Secured Bonds and Senior Unsecured Bonds on the consolidated balance sheets. On September 21, 2020 , the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the Senior Secured Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds, the Company recognized a loss on extinguishment of debt of $ 7,195 in the consolidated statements of operations and comprehensive loss, including the write-off of $ 3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $ 3,601 . Off Balance Sheet Arrangements As of December 31, 2020 and 2019, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results. 76 Table of Contents 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, 2020: (in thousands) Total Less than 1 year Years 2 to 3 Year 4 to 5 More than 5 years Long-term debt obligations $ 1,675,203 $ 87,703 $ 168,750 $ 1,418,750 $ - Purchase obligations 2,490,347 376,096 724,588 724,090 665,573 Lease obligations 191,991 47,135 56,066 36,006 52,784 Total $ 4,357,541 $ 510,934 $ 949,404 $ 2,178,846 $ 718,357 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, 2020. Purchase obligations The Company is party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. 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, 2020. In 2020, we entered into four LNG supply agreements for the purchase of 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029. The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract executed in December 2018. Lease obligations Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease. The Company currently has five vessels under time charter leases with non-cancellable terms ranging from nine months to seven years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services. We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 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 expect to begin to receive these ISO tanks and for the lease terms to commence beginning in the first 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 a space shared with affiliated companies in New York with lease terms up to 38 months and an office space in downtown Miami, with a lease term of 84 months. Summary of Critical Accounting Estimates The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management evaluates its estimates and related assumptions regularly and will continue to do so as we further grow our business. We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates. 77 Table of Contents Revenue recognition Our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, and beginning in the first quarter of 2020, power and steam which are outputs from our natural gas-fueled infrastructure. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is typically delivered in containers transported by truck to customer sites. Revenue from sales of LNG delivered by truck is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, either when the containers are shipped or delivered to the customers’ storage facilities, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, we have presented Operating revenue on an aggregated basis. We have concluded that variable consideration included in these agreements meets the exception for allocating variable consideration to each unit sold under the contract. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer. Our contracts with customers to supply LNG or natural gas may contain a lease of equipment. We allocate consideration received from customers between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. We estimate the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term. The estimated fair value of the leased equipment, as a percentage of the estimated total revenue from LNG or natural gas and leased equipment at inception, will establish the allocation percentage to determine the fixed lease payments and the amount to be accounted for under the revenue recognition guidance. The leases of certain facilities and equipment to customers are accounted for as finance or operating leases. The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net, on the consolidated balance sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and is included in Other revenue in the consolidated statements of operations and comprehensive loss. The principal components of the lease payment are reflected as a reduction to the net investment in the finance lease. For our operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the consolidated statements of operations and comprehensive loss. In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes development services revenue recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as we transfer control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under development until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and we recognize revenue for the interest income component over the term of the financing as Other revenue. Development services are typically included in arrangements that include other distinct performance obligations, and we allocate the transaction price to each performance obligation based on its standalone selling price (“SSP”) in relation to the aggregate value of the SSP of all performance obligations in the arrangement. Some of our performance obligations have observable inputs that are used to determine the SSP of those distinct performance obligations. Where SSP is not directly observable, we primarily determine the SSP using the cost-plus approach. In the circumstances when available information to determine SSP is highly variable or uncertain, we use the residual approach. Impairment of long-lived assets We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment. 78 Table of Contents Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance. We have considered that the market price of LNG can vary widely, including recent decreases throughout 2019 and 2020. Due to the decline in LNG prices, we executed three long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower than inventory purchased under our contract with our current supplier. Further, we were able to take advantage of lower market pricing for LNG to supply our operations for the second half of 2020, resulting in an overall lower average cost of LNG. Our long-term, take-or pay contracts to deliver natural gas or LNG to our customers also limit our exposure to fluctuations in natural gas and LNG as our pricing is based on the Henry Hub index plus a contractual spread. Based on the long-term nature of our contracts and the market value of the underlying assets, we do not believe that changes in the price of LNG indicate that a recoverability assessment of our assets is necessary. Further, we plan to utilize our own liquefaction facilities to manufacture our own LNG at attractive prices, secure LNG to supply our expanding operations and reduce our exposure to future LNG price variations in the long term. We have also considered the impacts of the ongoing COVID-19 pandemic, including the restrictions that governments may put in place and the resulting direct and indirect economic impacts, on our current operations and expected development budgets and timelines. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis, 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 any deterioration in the timing or volume of collections. Based on the essential nature of the services we provide to support power generation facilities, our development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicators that a recoverability assessment for our assets should be performed. The COVID-19 pandemic has also significantly impacted energy markets, and the price of oil has traded at historic low prices in 2020. Future expansion of our business is dependent upon LNG being a competitive source of energy and available at a lower cost than the cost to deliver other alternative energy sources, such as diesel or other distillate fuels. We do not believe that oil prices will remain at their historic low levels as evidenced by recent recovery, and we believe that LNG and natural gas will remain a competitive fuel source for customers. When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources. Share-based compensation We estimate the fair value of RSUs and performance stock units (“PSUs”) granted to employees and non-employees on the grant date based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model. As of December 31, 2020, management determined that it was not probable that the performance condition for our outstanding PSUs would be met. For these awards, compensation cost and the number of PSUs ultimately earned remains variable and compensation cost for these awards is recorded once achievement of the performance conditions becomes probable through the requisite service period. A cumulative adjustment to share-based compensation expense is recorded in the period that achievement of performance conditions becomes probable. Recent Accounting Standards For descriptions of recently issued accounting standards, see “Note 3 - Adoption of new and revised standards” to our notes to consolidated financial statements included elsewhere in this Annual Report. 79 Table of Contents