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Item 2. Management’s Discussion and Analysis

2021-05-07 compared with 2020-10-29 · 328 added, 261 removed, 157 unchanged (79% of the section changed)

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 that involve risks and uncertainties.

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 due to a variety of factors.

This discussion and analysis includes information that 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.

The results of operations for interim periods are not necessarily indicative of the results that may be expected for any other interim period or for a full year.

Unless otherwise indicated, dollar amounts are presented in thousands.

You should read “Part II, Item 1A.

Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and “Part I, Item 1A.

Risk Factors” in the Annual Report on Form 10-K for the year ended December 31, 2019 (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.

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, 2020 (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 GAAP.

The unaudited condensed consolidated financial statements as of and for the three and nine months ended September 30, 2020 included herein, reflect all adjustments which, in the opinion of management, are necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods on a basis consistent with the annual audited financial statements.

All such adjustments are of a normal recurring nature.

Unless the context otherwise requires, references to ‘‘NFE,’’ the ‘‘Company,’’ ‘‘we,’’ ‘‘us,’’ ‘‘our’’ and similar 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.

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 similar 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.

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.

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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” in our Annual Report.

We discuss this important goal in more detail in the Annual Report, “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.

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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 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 natural gas liquefaction and storage facility located in Miami-Dade County, Florida (the “Miami Facility”).

We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our 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”).

Montego Bay Facility

Our storage and regasification facility 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 LNG gallons (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage.

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 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 (“PPA”).

The CHP Plant also provides steam to Jamalco under a long-term take-or-pay steam supply agreement (“SSA”).

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.

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.

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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”).

In July 2020, we finalized the development of 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.

See “—Other Matters” for additional information regarding our San Juan Facility.

Miami Facility

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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.

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 Brazil.

On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.

(“Pecém”) and Energetica Camacari Muricy II S.A.

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 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.

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”).

Our La Paz Facility is expected to supply approximately 475,000 gallons of LNG (39,255 MMBtu) per day.

In February 2020, we entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, and we expect to construct a new approximately 300 MW natural gas-fired power plant that will consume approximately 800,000 gallons of LNG (65,000 MMBtus) per day.

On October 14, 2020, we signed a non-binding memorandum of understanding with the Philippine National Oil Company to advance the development of infrastructure to supply reliable, cost-competitive power and natural gas into the Philippine market.

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 approximately 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power.

In addition, we recently executed an agreement 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.

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 PPA 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.

We are currently developing a modular floating liquefaction facility to provide a 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 or similar floating infrastructure to enable a much lower cost and faster deployment schedule than today’s floating liquefaction vessels.

A permanently moored FSU will serve as an LNG storage facility alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

Recent Developments:

Hygo and GMLP Acquisitions

On April 15, 2021, the Company completed the previously announced acquisitions of Hygo Energy Transition Ltd.

(“Hygo”) and Golar LNG Partners LP (“GMLP”);

referred to as the “Hygo Merger” and “GMLP Merger,” respectively and, collectively, the “Mergers”.

NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger.

NFE paid $3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interest of GMLP’s general partner, totaling $251 million.

As a result of the Hygo Merger we acquired one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Facility”), a 50% interest in a 1.5G GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in development in Pará, Brazil ( the “Barcarena Facility”) and Santa Catarina, Brazil (the “Santa Catarina Facility”).

In addition, we acquired Hygo’s vessel fleet, which consists of the Golar Nanook , a newbuild FSRU moored and in service at the Sergipe Facility, and two operating LNG carriers, the Golar Celsius and the Golar Penguin , which may be converted into FSRUs.

As a result of the GMLP Merger we acquired 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.

Cash consideration for the GMLP Merger was funded from proceeds from a private offering of $1.5 billion aggregate principal amount of senior secured notes due 2026 (the “2026 Notes”) completed on April 12, 2021.

The 2026 Notes bear interest at 6.50% per annum and were issued at an issue price equal to 100% of principal.

On April 15, 2021, we also entered into a $200 million senior secured revolving facility (the “Revolving Facili ty”).

The Revolving Facility has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.

COVID-19 Pandemic

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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 nine months ended September 30, 2020, we have incurred approximately $0.9 million for safety measures introduced into our operations and other responses to the COVID-19 pandemic.

For the three months ended March 31, 2021, we have incurred approximately $0.4 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 nine months ended September 30, 2020 from the COVID-19 pandemic;

We have not experienced significant disruptions in development projects and daily 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.

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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.

We received an order from 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.

We do not know if or when FERC will respond to our reply, or the outcome of any such response.

Results of Operations – Three and Nine Months Ended September 30, 2020 compared to Three and Nine Months Ended September 30, 2019

Three Months Ended September 30,

Nine Months Ended September 30,

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, 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, have sought rehearing of the March 19, 2021 FERC order and such rehearing requests remain pending before FERC.

FERC’s orders in the proceeding would be subject to subsequent judicial review.

Results of Operations – Three Months Ended March 31, 2021 compared to Three Months Ended March 31, 2020

Three Months Ended March 31,

Operating revenue

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Total operating expenses

Operating income (loss)

Operating loss

Interest expense

Other expense, net

Other (income) expense, net

Loss on extinguishment of debt, net

Loss before taxes

Tax expense (benefit)

Operating revenue from the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilities increased $48,518 and $130,321 for the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019, respectively.

Tax (benefit)

Operating revenue from the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilities increased $27,694 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020.

The increase was primarily driven by increases in volumes sold from the Old Harbour Facility, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020:

For the three months ended September 30, 2020, we recognized $50,064 of revenue from volumes sold at the Old Harbour Facility, as compared to $11,386 for the three months ended September 30, 2019.

Revenue recognized in the third quarter of 2020 included $26,686 from sales to the Old Harbour Power Plant and $23,378 from natural gas utilized in the CHP Plant and Jamalco’s boilers.

For the three months ended September 30, 2020, the volume delivered to the Old Harbour Power Plant was 26.9 million gallons (2.2 TBtu) and the volume utilized in the CHP Plant and Jamalco’s boilers was 28.6 million gallons (2.4 TBtu).

For the three months ended September 30, 2019, the volume delivered to the Old Harbour Power Plant was 2.6 million gallons (0.2 TBtu).

For the nine months ended September 30, 2020, we recognized $129,313 of revenue from volumes sold at the Old Harbour Facility, as compared to $15,440 for the nine months ended September 30, 2019.

Revenue recognized for the nine months ended September 30, 2020 included $79,562 from sales to the Old Harbour Power Plant and $49,751 from natural gas utilized in the CHP Plant and Jamalco’s boilers.

For the nine months ended September 30, 2020, the volume delivered to the Old Harbour Power Plant was 78.4 million gallons (6.5 TBtu) and the volume utilized in the CHP Plant and Jamalco’s boilers was 62.4 million gallons (5.2 TBtu).

For the nine months ended September 30, 2019, the volume delivered to the Old Harbour Power Plant was 4.6 million gallons (0.4 TBtu).

Additional revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco adding $7,280 and $15,957 in revenue for the three and nine months ended September 30, 2020, respectively.

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 three and nine months ended September 30, 2020, resulting in an increase of $3,943 and $11,829 to Operating revenue, respectively.

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 $559 to $19,572 for the three months ended September 30, 2020 as compared to $20,131 for the three months ended September 30, 2019.

The delivered volume at the Montego Bay Facility decreased by 1.5 million gallons ( 0.1 TBtu) from 25.4 million gallons ( 2.1 TBtu) during the three months ended September 30, 2019 to 23.9 million gallons ( 2.0 TBtu) during the three months ended September 30, 2020.

Revenue from sales at the Montego Bay Facility decreased by $11,152 to $57,243 for the nine months ended September 30, 2020 as compared to $68,395 for the nine months ended September 30, 2019.

The delivered volume at the Montego Bay Facility decreased by 11.4 million gallons ( 0.8 TBtu) from 81.9 million gallons ( 6.7 TBtu) during the nine months ended September 30, 2019 to 70.5 million gallons ( 5.9 TBtu) during the nine months ended September 30, 2020.

Other revenue includes revenue for 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 $38,684 and $56,260 for the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019, respectively, and the increases were due to the following:

Increase of $49,541 and $76,410 for development services in Puerto Rico for the three and nine months ended September 30, 2020, respectively, 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 three months ended September 30, 2020 included $51,974 for the customer’s use of 58.6 million gallons (4.8 TBtu) of natural gas as part of commissioning their assets.

Development services revenue recognized in the nine months ended September 30, 2020 included $68,458 for the customer’s use of 77.9 million gallons (6.4 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 three and nine months ended September 30, 2020, we recognized $0 and $687, respectively, for the completion of infrastructure projects for customers of the CHP Plant, as compared to $7,762 and $11,670 for the three and nine months ended September 30, 2019, respectively.

Decrease in interest income associated with the direct financing lease of the Montego Bay Facility, as all amounts recognized as revenue for activities at the Montego Bay Facility were included in Operating revenue for the three months and nine months ended September 30, 2020.

For the three months ended March 31, 2021, we recognized $51,644 of revenue from volumes sold at the Old Harbour Facility, as compared to $35,777 for the three months ended March 31, 2020, including additional revenue of $16,830 from natural gas utilized in the CHP Plant and Jamalco’s boilers.

For the three months ended March 31, 2021, the volume delivered to the Old Harbour Facility was 53.0 million gallons (4.4 TBtu).

For the three months ended March 31, 2020, the volume delivered to the Old Harbour Facility was 42.1 million gallons (3.5 TBtu).

The increase in volumes from sales to the Old Harbour Facility was primarily due to volumes delivered to the CHP Plant and Jamalco’s boilers increasing by 15.7 million gallons (1.3 TBtu) to 25.5 million gallons (2.1 TBtu) from 9.8 million gallons (0.8 TBtu) in the three months ended March 31, 2020.

Revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco of $7,136 for the three months ended March 31, 2021 as compared to $1,731 in revenue for the three months ended March 31, 2020.

Operating revenue was also impacted by operations at our Montego Bay Facility.

Sales at the Montego Bay Facility increased by $1,956 from $22,823 for the three months ended March 31, 2020 to $24,779 for the three months ended March 31, 2021.

The increase in sales at the Montego Bay Facility was primarily due to an increase in sales to industrial end-user customers, offset by a minor decrease in consumption by the Bogue Power Plant.

Volumes delivered at the Montego Bay Facility remained relatively consistent for the three months ended March 31, 2021 as compared to the three months ended March 31, 2021, increasing by 0.1 million gallons (0.0 TBtu) from 23.5 million gallons (2.0 TBtu) during the three months ended March 31, 2020 to 23.6 million gallons (2.0 TBtu) during the three months ended March 31, 2021.

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 $43,460 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020, and the increases were due to an increase in revenue for development services in Puerto Rico for the three months ended March 31, 2021, including gas used by our customer for testing and commissioning their assets.

Development services revenue recognized in the three months ended March 31, 2021 included $45,618 for the customer’s use of 48.7 million gallons (4.0 TBtu) of natural gas as part of commissioning their assets.

The increase was partially offset by a decrease in development services revenue of $1,033 related to conversion of the customer’s infrastructure within the San Juan Power Plant.

Cost of sales

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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 increased $25,833 and $86,556 for the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019, respectively.

Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $29,776 and $82,586 for the three and nine months ended September 30, 2020, respectively.

The increase was primarily attributable to the increase in volumes delivered of 366% and 220% compared to the three and nine months ended September 30, 2019, respectively, partially offset by the decrease in LNG cost.

The weighted-average cost of LNG purchased from third parties decreased from $0.66 per gallon ($8.02 per MMBtu) for the three months ended September 30, 2019 to $0.37 per gallon ($4.44 per MMBtu) for the three months ended September 30, 2020.

The weighted-average cost of LNG purchased from third parties decreased from $0.77 per gallon ($9.32 per MMBtu) for the nine months ended September 30, 2019 to $0.51 per gallon ($6.13 per MMBtu) for the nine months ended September 30, 2020.

The weighted-average cost of our inventory balance as of September 30, 2020 and December 31, 2019 was $0.29 per gallon ($3.47 per MMBtu) and $0.64 per gallon ($7.70 per MMBtu), respectively.

Charter costs associated with our expanded fleet increased Cost of sales by $3,175 and $5,247 for the three and nine months ended September 30, 2020.

The increase was attributable to a full nine months 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 d ecrease in costs associated with the infrastructure projects for customers of the CHP Plant of $6,751 and $ 9,657 for the three and nine months ended September 30, 2020, respectively.

Cost of sales increased $28,455 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020.

Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $22,454 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020.

The increase was primarily attributable to an 89% increase in volumes delivered, inclusive of volumes delivered from our Miami Facility, compared to the three months ended March 31, 2020, partially offset by the decrease in LNG cost.

The weighted-average cost of LNG purchased from third parties and delivered decreased from $0.67 per gallon ($8.10 per MMBtu) for the three months ended March 31, 2020 to $0.51 per gallon ($6.17 per MMBtu) for the three months ended March 31, 2021.

The weighted-average cost of our inventory balance as of March 31, 2021 and December 31, 2020 was $0.55 per gallon ($6.63 per MMBtu) and $0.40 per gallon ($4.81 per MMBtu), respectively.

Charter costs increased Cost of sales by $2,241 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 .

The increase was attributable to an additional vessel in our fleet associated with our San Juan Facility after our assets were placed in service in the third quarter of 2020, as well as credits received in the first quarter of 2020 that did not recur in the first quarter of 2021.

Operations and maintenance

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

Operations and maintenance increased $5,095 and $13,176 for the three and nine months ended September 30, 2020, as compared to the three and nine months ended September 30, 2019, respectively.

The increase is primarily a result of higher logistics costs of $3,007 and $6,560 for the three and nine months ended September 30, 2020, respectively, primarily associated with the operations of additional charter vessels deployed.

Operations and maintenance also increased by $2,838 and $6,179 for the three and nine months ended September 30, 2020, respectively, for costs of operating the CHP Plant for the period after commencement of commercial operations on March 3, 2020 as well as higher payroll costs to operate our facilities.

These increases were partially offset by decrease in demurrage costs.

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 three months ended March 31, 2021 was $16,252, which increased $7,769 from $8,483 for the three months ended March 31, 2020.

The increase was primarily the result of operating facilities in the first quarter of 2021 that were still in development or had just commenced commercial operations in the first quarter of 2020.

Operations and maintenance increased by the costs of operating the San Juan Facility of $3,206 and an increase in the cost to operate the CHP Plant of $1,844.

Higher maintenance costs of $1,352 also contributed to the increased operations and maintenance costs for the three months ended March 31, 2021.

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.

Selling, general and administrative decreased $10,064 and $31,530 for the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019, respectively.

For the three months ended September 30, 2020, development costs incurred that do not qualify for capitalization decreased $12,055 and share-based compensation expense decreased $5,874 as compared to the same period in the prior year.

These decreases were partially offset by increased in payroll costs associated with increased headcount of $5,565 and increased professional fees of $2,550, including of third-party fees recognized in connection with the issuance of the Senior Secured Notes and repayment of the Credit Agreement.

For the nine months ended September 30, 2020, share-based compensation expense decreased by $29,612, professional fees decreased $6,420 and development costs incurred that do not qualify for capitalization decreased $4,131 as compared to the same period in the prior year.

These decreases were partially offset by $7,179 of higher payroll costs associated with increased headcount.

Selling, general and administrative for the three months ended March 31, 2021, was $45,181 which increased $16,643 from $28,538 for the three months ended March 31, 2020.

The increase was primarily attributable to $11,563 of professional services costs and other costs associated with the Mergers.

The increase was also attributable to $4,050 of higher payroll costs associated with increased headcount, partially offset by reductions to other administrative costs.

Contract termination charges and loss on mitigation sales

Contract termination charges and loss on mitigation sales for the three and nine months ended September 30, 2020 was $0 and $124,114, respectively.

The pricing for LNG in the open market continues to be significantly lower than the pricing in our LNG supply agreement.

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 both take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs.

We intend to purchase LNG in the open market for the remainder of our needs in 2020, significantly reducing our LNG supply cost.

Purchases of LNG in the open market have reduced our cost of LNG from $0.64 per gallon ($7.75 per MMBtu) for the three months ended June 30, 2020 to $0.37 per gallon ($4.44 per MMBtu) for the three months ended September 30, 2020.

The weighted-average cost of our inventory balance has decreased from $0.59 per gallon ($7.13 per MMBtu) as of June 30, 2020 to $0.29 per gallon ($3.47 per MMBtu) as of September 30, 2020.

We have experienced lower than expected consumption by some of our customers, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica in May and June 2020.

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.

We did not have such transactions during the three months ended September 30, 2020 or during the same periods in the prior year.

Loss on mitigation sales for the three months ended March 31, 2021 and 2020 was $0 and $208, respectively.

In the first quarter of 2020, we incurred losses associated with undelivered quantities of LNG under firm purchase commitments due to storage capacity constraints.

In these situations, our supplier will attempt to sell the undelivered quantity through a mitigation sale, and the losses incurred under the firm purchases are partially offset by this sale of the undelivered amount to third parties for amounts lower than the contracted price, which resulted in a loss of $208.

We did not have such transactions during the three months ended March 31, 2021.

Depreciation and amortization

Depreciation and amortization increased $7,559 and $16,632 for the three and nine months ended September 30, 2020, respectively.

Depreciation and amortization increased $4,636 for the three months ended March 31, 2021.

The increase was primarily due to the following:

Increase in depreciation of $1,214 and $4,320 for our Old Harbour Facility that went into service in June 2019 for the three and nine months ended September 30, 2020, respectively;

Increase in depreciation of $2,820 and $6,493 for the CHP Plant that went into service in March 2020 for the three and nine months ended September 30, 2020, respectively;

Increase in depreciation of $1,994 for the San Juan Facility that went into service in July 2020 for both the three and nine months ended September 30, 2020;

Additional depreciation of $1,274 and $3,599 recognized on our Montego Bay Facility during the three and nine months ended September 30, 2020, respectively.

These assets were presented as direct financing leases prior to the adoption of ASC 842, and no depreciation for such assets was previously recorded.

Increase in depreciation of $2,207 for the CHP Plant that went into service in March 2020;

Increase in depreciation of $2,385 for the San Juan Facility that went into service in July 2020.

Interest expense

Interest expense increased $14,839 and $36,444 for the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019, respectively.

These increases were a result of the additional principal balances outstanding during 2020 under the Senior Secured Bonds, Senior Unsecured Bonds and the Credit Agreement (all defined below), as compared to the Term Loan Facility which was extinguished in January 2020.

The principle balance of the Term Loan Facility was $496,250 as of September 30, 2019 as compared to combined outstanding amounts principle balances on the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds of $980,000 prior to the repayment and replacement of these facilities with the Senior Secured Notes in September 2020.

Other expense, net

Other expense, net increased $781 and $4,046 for the three and nine months ended September 30, 2020 as compared to the three and nine months ended September 30, 2019, respectively.

The increase in expense for the three months ended September 30, 2020 was primarily due to the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG and a decrease in interest income, partially offset by decrease in unrealized loss on investment in equity securities .

For the nine months ended September 30, 2020, the increase in expense was primarily a result of changes in fair value of the derivative liability and equity agreement and the decrease in interest income.

Interest expense for the three months ended March 31, 2021 was $18,680, which increased $4,790 from $13,890 for the three months ended March 31, 2020, primarily as a result of decreased capitalization of interest as both our CHP Plant and our San Juan Facility were placed into service in 2020, as well as higher principal balances outstanding during 2021.

The increase in expense was partially offset by a reduction to the amortization of financing costs.

Other (income) expense, net

Other income, net for the three months ended March 31, 2021 was $604, which increased $1,215 from expense of $611 for the three months ended March 31, 2020, primarily as a result of the unrealized loss on our investment in equity securities of $2,400 in the first quarter of 2020 that did not recur in the first quarter of 2021.

We also recognized income from the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG.

Loss on extinguishment of debt, net

Loss on extinguishment of debt for the three ended September 30, 2020 was $23,505 as a result of the extinguishment of the Senior Secured Bonds, Senior Unsecured Bonds and the Credit Agreement in September 2020.

Loss on extinguishment of debt for the nine months ended September 30, 2020 of $33,062 also included the loss recognized upon the extinguishment of the Term Loan Facility in January 2020.

Tax expense (benefit)

Tax expense (benefit) for the three and nine months ended September 30, 2020 was $1,836 and $1,949, respectively, compared to tax (benefit) expense of $(64) and $337 for the three and nine months ended September 30, 2019, respectively.

We continue to have valuation allowances in many of our foreign jurisdictions and tax expense for earnings generated in foreign jurisdictions has been limited.

As our Puerto Rican operations begin to generate earnings, we expect to recognize current tax expense at the lower tax rate applicable under our Puerto Rican tax decree.

Our expectation of current tax expense in Puerto Rico has increased our tax expense for the three and nine months ended September 30, 2020, albeit at a lower effective tax rate than the U.S.

Loss on extinguishment of debt for the three months ended March 31, 2020 was $9,557 as a result of the extinguishment of the Term Loan Facility in January 2020.

We did not have such transactions during the three months ended March 31, 2021.

Tax (benefit)

We recognized a tax benefit for the three months ended March 31, 2021 of $877, compared to tax benefit of $4 for the three months ended March 31, 2020.

The increase in benefit for the three months ended March 31, 2021 was primarily driven by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $3,010, partially offset by income tax expense recorded for certain profitable foreign operations.

The Company determined that the valuation allowance should be released based on forecasted pre-tax profits in this jurisdiction.

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 three months ended March 31, 2021 as compared to the three months ended March 31, 2020 without any historical net operating losses to offset additional tax expense.

During the third quarter of 2020, we placed our assets at the San Juan Facility into service, and since that point, 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

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Our historical financial results do not include significant projects that have recently been completed or are near completion.

Our results of operations for the nine months ended September 30, 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 LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”), the LNG facility on the Shannon Estuary near Ballylongford, Ireland (the “Ireland Facility”), and any potential future developments in the Philippines.

Our historical financial results do not reflect changes to our current long-term LNG supply agreement as well a new LNG supply agreement 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 three and nine months ended September 30, 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 in the third quarter of 2020, we purchased all volumes needed for our operations on the open market, significantly reducing our LNG supply costs.

Our purchases of LNG in the open market have reduced our cost of LNG from $0.64 per gallon ($7.75 per MMBtu) for the three months ended June 30, 2020 to $0.37 per gallon ($4.44 per MMBtu) for the three months ended September 30, 2020.

The weighted-average cost of our inventory balance has decreased from $0.59 per gallon ($7.13 per MMBtu) as of June 30, 2020 to $0.29 per gallon ($3.47 per MMBtu) as of September 30, 2020.We expect to continue to purchase LNG on the open market for the remainder of 2020.

We also expect that LNG prices will recover over the long term, and in 2019, w e executed an LNG supply agreement to purchase 27.5 TBtus annually beginning in 2022 at prices that are lower than the prices under our contract with our current supplier.

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 on September 2, 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.

We expect to 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.

Our results of operations for the three months ended March 31, 2021 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility.

We are finalizing development of our La Paz Facility 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, but not limited to, potential developements in Brazil and the Ireland Facility.

Our historical financial results do not reflect 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 three months ended March 31, 2021, a significant portion of which is under an LNG supply agreement signed in 2018.

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.

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.

Our historical financial results do not include the 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 acquired the Sergipe Facility, a 50% interest in the Sergipe Power Plant, as well as the Barcarena Facility and the Santa Catarina Facility that are currently in development.

In addition, we acquired one FSRU in service at the Sergipe Facility and two operating LNG carriers which may be converted into FSRUs.

Upon completion of the acquisition of GMLP, we acquired 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 in the second quarter 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, which may be significant.

Liquidity and Capital Resources

We believe we will have sufficient liquidity from proceeds from recent borrowings 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.

We have historically funded our developments through proceeds from our IPO and debt financing as follows:

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.

On March 21, 2019, we drew the remaining availability on our Term Loan Facility and had $495,000 of outstanding principal as of December 31, 2019.

On September 5, 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.

On September 2, 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.

We have assumed total expenditures for all completed and existing projects to be approximately $ 856 million, with approximately $ 737 million having already been spent through September 30, 2020.

This estimate represents the expenditures necessary to complete the La Paz 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 September 30, 2020, we have spent approximately $ 157 million to develop the Pennsylvania Facility.

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 Revolving Facility and cash generated from operations.

We may also elect to generate additional liquidity through future debt or equity issuances or debt refinancings to fund developments and transactions.

We have historically funded our developments through proceeds from our IPO and debt and equity financing as follows:

In January 2020, we borrowed $800,000 under a credit agreement, and repaid our prior term loan facility in full.

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.

On April 12, 2021, we issued $1.5 billion of 2026 Notes.

The 2026 Notes bear interest at 6.50% per annum and were issued at an issue price equal to 100% of principal.

No principal payments are due on the 2026 Notes until maturity in 2026.

The Company used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses.

On April 15, 2021, we entered into the $200 million Revolving Facility that has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.

We have assumed total expenditures for all completed and existing projects to be approximately $1,239 million, with approximately $839 million having already been spent through March 31, 2021.

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, cash flows from operations and borrowings under our Revolving Facility.

We may also seek to fund our developments through debt refinancings.

We are currently exploring the potential refinancing of the Golar Nanook with a sale-leaseback or similar financing.

We cannot assure whether any such refinancing will occur.

Through March 31, 2021, we have spent approximately $144 million to develop the Pennsylvania Facility.

Approximately $21 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 $123 million, has been capitalized.

During the third quarter of 2020, we paid 50% of the $105,000 cancellation fee in connection with the termination of cargoes for the remainder of the year.

The remaining cancellation fee was paid in October 2020.

The following table summarizes the changes to our cash flows for the nine months ended September 30, 2020 and 2019, respectively:

Nine Months Ended September 30,

Certain of the debt facilities of each of Hygo and GMLP or their respective subsidiaries remained outstanding following the closing of the Mergers.

The following is a description of the debt facilities for each of Hygo and GMLP that remain outstanding following the closing of the Mergers.

In the future, we will need to repay or refinance this additional indebtedness which could adversely affect our liquidity and capital resources.

There can be no assurances that we will be able to refinance this indebtedness on favorable terms or at all.

Sergipe Debt Financing

To finance construction of the Sergipe Facility and the Sergipe Power Plant, in April 2018, CELSE—Centrais Elétricas de Sergipe S.A.

(“CELSE”) signed financing agreements with amounts made available by banks and multilateral organizations throughout 2018 and 2019 (the “CELSE Facility”).

As of December 31, 2020, amounts outstanding and the effective interest rates under the CELSE Facility were as set forth below.

Principal and interest payments are due each October and April, beginning October 2020.

The CELSE Facility matures in April 2032.

Credit facility ( Real and USD in millions)

interest rate

844.9 ($156.8)

Inter-American Development Bank

694.6 ($128.9)

IDB China Fund

Also in April 2018, CELSE issued debentures in the aggregate principal amount of R$3,370.0 million (net proceeds of $874 million), due April 2032, bearing interest at a fixed rate of 9.85% (the “CELSE Debentures”).

As of December 31, 2020, the balance of the CELSE Debentures was R$2,571.0 million ($477.3 million).

Interest is payable on the CELSE Debentures semi-annually on each April 15 and October 15, beginning on October 15, 2018.

The CELSE Debentures are amortized and repaid in 24 consecutive semi-annual installments on each of April 15 and October 15, commencing on October 15, 2020.

The indenture governing the CELSE Debentures contains covenants that:

(i) requires CELSE to maintain a historical debt service coverage ratio for a twelve month period on or after March 31, 2021 of no less than 1.10 to 1.00;

(ii) prohibit certain restricted payments;

(iii) limit the ability of CELSE from creating any liens or incurring additional indebtedness;

(iv) prohibit certain fundamental changes;

(v) limit the ability of CELSE to transfer or purchase assets;

(vi) prohibit certain affiliate transactions;

(vii) limit the ability of CELSE to make change orders or give other directions under the documents related to the construction and operation of the project in certain circumstances;

(viii) limit the ability of CELSE to enter into additional contracts;

(ix) limit CELSE’s operating expenses and capital expenditures;

and (x) prohibit CELSE from transferring, purchasing or otherwise acquiring any portion of the CELSE Debentures, other than pursuant to the exercise of the put option.

On April 12, 2018, CELSEPAR—Centrais Elétricas de Sergipe Participações S.A.

(“CELSEPAR”) entered into a Standby Guarantee and Credit Facility Agreement with GE Capital EFS Financing, Inc.

(“GE Capital”), as lender, and Ebrasil Energia Ltda.

(“Ebrasil”) and Golar Power Brasil Participações S.A (“Golar Brazil”), each as sponsor (the “GE Credit Facility”).

Pursuant to the GE Credit Facility, GE Capital agreed to provide $120.0 million in credit support in respect of CELSEPAR’s obligation to make certain contingent equity contributions to CELSE.

Amounts disbursed under the GE Credit Facility accrue interest at a fixed rate of LIBOR plus a margin of 11.4% and are payable on May 30 and November 30 each year, beginning on May 30, 2021.

The GE Credit Facility matures on November 30, 2024.

As of December 31, 2020, there was R$689.4 million ($132.0 million) outstanding under the GE Credit Facility.

The GE Credit Facility includes covenants and events of default that are customary for similar transactions.

Debenture Loan

On September 10, 2019, Hygo’s subsidiary, Golar Brazil issued debentures in the aggregate principal amount of R$300.0 million ($55.7 million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debentures”).

The offering resulted in net proceeds to Golar Brazil, after deducting applicable discounts and commissions and offering expenses, of R$295.0 million ($54.8 million).

Interest is payable on the Debentures semi-annually on each September 13 and March 13, beginning on September 13, 2020.

Principal due under the Debentures is amortized semi-annually on each September 13 and March 13, beginning September 13, 2020.

Golar Nanook Leaseback and Credit Facility

In September 2018, Golar FSRU8 Corp., a corporation organized in the Marshall Islands, as subsidiary of Hygo, entered into a sale and leaseback transaction with Compass Shipping 23 Corporation Limited in respect of the Golar Nanook (the “Nanook Leaseback”).

In September 2018, Compass Shipping 23 Corporation Limited, the owner of the Golar Nanook, entered into a twelve-year, $277 million credit facility (the “Nanook Facility”).

Although we have no control over the funding arrangements of Compass Shipping 23 Corporation Limited, we expect to be the primary beneficiary of the Golar Nanook and therefore expect to consolidate the Nanook Facility in our financial results.

The Nanook Facility bears interest at LIBOR plus a margin equal to 3.5% and is repayable in a balloon payment on maturity.

The Nanook Facility matures in September 2030.

The Golar Nanook is part of the Sergipe Facility.

The terminal’s assets consist of (i) our FSRU, the Golar Nanook , which is under a 25-year bareboat charter with CELSE (the “Sergipe FSRU Charter”), (ii) specialized mooring infrastructure and (iii) a dedicated 8 kilometer pipeline which connects to the adjacent Sergipe Power Plant.

The Golar Nanook is financed through a twelve year sale-leaseback transaction with the right and obligation to repurchase the vessel at the end of the lease period.

The balance of the infrastructure as well as our interest in the Sergipe Power Plant is owned through our joint venture, CELSEPAR.

The Golar Nanook operates under a 25-year bareboat charter with CELSE (the “Sergipe FSRU Charter”).

Pursuant to the Sergipe FSRU Charter, the Golar Nanook generates approximately $44 million per year in bareboat charter earnings, indexed to the Consumer Price Index (“CPI”), with operating expenditures passed through to CELSE.

Pursuant to the terms of the Sergipe FSRU Charter, we expect total revenues less estimated operating costs, without adjusting for inflation, of $1.1 billion over the 25-year term.

The charter terminates on December 31, 2044.

In addition to the charter, we expect to generate incremental revenue in the Sergipe Facility from downstream customers.

The Sergipe Facility is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG.

We expect the terminal to utilize approximately 230,000 MMBtu/d (30% of the terminal’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant at full dispatch.

CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant will deliver power to 26 committed offtakers, including investment grade counterparties, for a period of 25 years.

These PPAs provide for guaranteed annual capacity payments of R$1.6 billion at an expected contracted EBITDA margin on gross revenue of 61% (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred).

The fixed capacity payments are adjusted annually for the Extended National Consumer Price Index (the “IPCA”), the Brazilian inflation-targeting system, which has historically offset changes in the exchange rate between the U.S.

dollar and the Brazilian real.

Annual revenues less operating costs are expected to be R$1.1 billion.

Based on the terms of our PPAs, we expect total contracted revenues over the 25-year term, without adjusting for inflation, of R$41.0 billion.

We also expect to generate incremental variable revenue during periods we elect to dispatch and sell power from the facility.

Golar Penguin Leaseback and Credit Facility

In December 2019, Golar Hull M2023 Corp., a corporation organized in the Marshall Islands, as subsidiary of Hygo, entered into a sale and leaseback transaction with Oriental LNG 02 Limited in respect of the Golar Penguin (the “Penguin Leaseback”).

Payments are due quarterly in 24 installments of $1.89 million, with a balloon payment of approximately $68.0 million upon maturity.

The Penguin Leaseback also contains certain covenants that, among other things, (i) require GLNG to maintain a consolidated net worth equal or greater to $450.0 million and maintain current assets equal to or greater than current liabilities and (ii) require the guarantor to maintain free liquid assets with aggregate value equal to or greater than $50.0 million.

The Penguin Leaseback is cross-collateralized with a vessel under a sale and leaseback transaction between a subsidiary of GLNG and Oriental LNG 01 Limited, whereby a default under one sale and leaseback transaction automatically results in a default under the other.

In connection with the Hygo Merger, a Supplemental Deed to the Penguin Leaseback was executed pursuant to which the cross-collateralization and related default were removed.

The Supplemental Deed is effective subject to certain conditions, including consent from the lenders to the Penguin Facility (as defined below) set out therein.

In October 2020, Oriental LNG 02 Limited, the owner of the Golar Penguin, entered into a financing agreement to refinance its existing $113.4 million loan facility (the “Penguin Facility”).

Although we have no control over the funding arrangements of Oriental LNG 02 Limited, we expect to be the primary beneficiary of the Golar Penguin and therefore expect to be required to consolidate the Penguin Facility in our financial results.

The Penguin Facility bears interest at LIBOR plus a margin of 1.7% and is repayable in quarterly installments over a term of approximately six years.

Golar Celsius Leaseback and Credit Facility

On March 3, 2020, Golar Hull M2026 Corporation, a corporation organized in the Marshall Islands, as subsidiary of Hygo, entered into in a sale and leaseback transaction with Noble Celsius Shipping Limited in respect of the Golar Celsius (the “Celsius Leaseback”).

In March 2020, Noble Celsius Shipping Limited, the owner of the Golar Celsius, entered into a three-year loan facility for $118.2 million (the “Celsius Facility”).

The Celsius Facility is denominated in U.S.

dollars and bears interest at 4.0% and is repayable at the end of the three-year period.

Although we have no control over the funding arrangements of Noble Celsius Shipping Limited, we expect to be the primary beneficiary of the Golar Celsius and therefore expect to consolidate the Celsius Facility in our financial results.

Golar Eskimo Leaseback and Credit Facility

In November 2015, GMLP entered into a sale and leaseback transaction with a subsidiary, Sea 23 Leasing Co.

Limited (“Eskimo SPV”) of China Merchants Bank Leasing in respect of the Golar Eskimo (the “Eskimo Leaseback”).

The Eskimo Leaseback also contains certain covenants that, among other things and subject to certain exceptions and qualifications require:

(a) GMLP to maintain a minimum level of liquidity of $30 million and consolidated net worth of $123.95 million, (b) GMLP to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (c) GMLP to maintain a minimum percentage of the value of the Golar Eskimo over the relevant outstanding balances of 110%.

The Eskimo Leaseback is cross-collateralized with a vessel under a sale and leaseback transaction between a subsidiary of GLNG and Sea 24 Leasing Co.

Limited, whereby a default under one sale and leaseback transaction automatically results in a default under the other.

In November 2015, Eskimo SPV, which is the legal owner of the Golar Eskimo, entered into a long-term loan facility (the “Eskimo SPV Debt”).

The facility bears interest at a rate of LIBOR plus a margin.

Although we have no control over the funding arrangements of the Eskimo SPV, we will be the primary beneficiary of the Golar Eskimo and therefore will be required to consolidate the Eskimo SPV Debt in our financial results.

In conjunction with the closing of the GMLP Merger, GMLP delivered an irrevocable notice to terminate the Eskimo Leaseback and repurchase the Golar Eskimo, and we will complete the repurchase in the third quarter of 2021.

Golar Hilli Leaseback

Golar Hilli Corporation (“Hilli Corp”) is a party to a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”).

GMLP’s 50% share of Hilli Corp’s indebtedness of $778.5 million amounted to $389.3 million as of December 31, 2020.

Pursuant to the GMLP Guarantee, GMLP is required to comply with the following covenants and ratios:

(i) free liquid assets of at least $30 million throughout the Hilli Leaseback period;

(ii) a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1;

(iii) a consolidated tangible net worth of $123.95 million, and (iv) a minimum EBITDA to consolidated debt service for the previous 12 months of 1.20:1.

Series A Preferred Units

Distributions on the Preferred Units are payable out of amounts legally available therefor at a rate equal to 8.75% per annum of the stated liquidation preference.

In the event of a liquidation, dissolution or winding up, whether voluntary or involuntary, holders of Preferred Units will have the right to receive a liquidation preference of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of payment, whether declared or not.

At any time on or after October 31, 2022, the Preferred Units may be redeemed, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon on the date of redemption, whether declared or not.

The following table summarizes the changes to our cash flows for the three months ended March 31, 2021 and 2020, respectively:

Three Months Ended March 31,

(in thousands)

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Financing activities

Net increase in cash, cash equivalents, and restricted cash

Net (decrease) increase in cash, cash equivalents, and restricted cash

Cash (used in) operating activities

Our cash flow used in operating activities was $115,710 for the nine months ended September 30, 2020, which decreased by $39,051 from $154,761 for the nine months ended September 30, 2020.

Our net loss when adjusted for non-cash items was $6,787 lower than the net loss adjusted for non-cash items for the nine months ended September 30, 2019, reflecting lower cash used as a result of our operations for the nine months ended September 30, 2020.

The reduction in cash flow used in operating activities for the nine months ended September 30, 2020 was also due to more favorable changes in working capital accounts.

Our cash flow used in operating activities was $111,986 for the three months ended March 31, 2021, which increased by $60,675 from $51,311 for the three months ended March 31, 2020.

The increase in cash flow used in operating activities for the three months ended March 31, 2021 was due to unfavorable changes in working capital accounts, primarily significant increases in receivables, inventory and decrease to accounts payable and accrued liabilities.

In total changes in these working capital accounts resulted in $46,793 of additional cash used in operating activities in the first quarter of 2021.

Cash (used in) investing activities

Our cash flow used in investing activities was $115,704 for the nine months ended September 30, 2020, which decreased by $179,331 from $295,035 for the nine months ended September 30, 2019.

Cash outflows for investing activities during the nine months ended September 30, 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 nine months ended September 30, 2019 included 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 $291,816 for the nine months ended September 30, 2020, which decreased by $301,185 from $593,001 for the nine months ended September 30, 2019.

Cash provided by financing activities during the nine months ended September 30, 2020 was due to proceeds received from the borrowings under the Senior Secured Notes of $1,000,000, the Credit Agreement of $800,000 and Senior Secured Bonds of $52,144.

A portion of these proceeds was 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.

Cash flow provided by financing activities during the nine months ended September 30, 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.

Our cash flow used in investing activities was $90,257 for the three months ended March 31, 2021, which increased by $34,209 from $56,048 for the three months ended March 31, 2020.

Cash outflows for investing activities during the three months ended March 31, 2021 were primarily used for development projects in Nicaragua and Mexico.

During the three months ended March 31, 2020, we completed the CHP Plant and were in the final stages of development of the San Juan Facility, and as such, we incurred lower cash outflows for investing activities for the three months ended March 31, 2020.

Cash (used in) provided by financing activities

Our cash flow used in financing activities was $47,891 for the three months ended March 31, 2021, which decreased by $353,480 from cash provided by financing activities of $305,589 for the three months ended March 31, 2020.

Cash 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.

Cash flow provided by financing activities during the three months ended March 31, 2020 was primarily due to borrowings under the Credit Agreement of $800,000, partially offset by an original issue discount of $20,000 and transaction costs and other fees to obtain the Credit Agreement of $14,069.

A portion of these proceeds was used to fund the repayment of the Term Loan Facility of $506,402.

Additionally, the remaining proceeds from the Senior Secured Bonds of $52,144 were received during the first quarter of 2020.

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 144A under the Securities Act (the “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 144A under the Securities Act (the “2025 Notes”).

Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021;

no principal payments are due until maturity on September 15, 2025.

We may redeem the 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 provides for customary events of default and prepayment provisions.

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 $17,666 in origination, structuring and other fees.

Issuance costs of $13,638 were deferred as a reduction of the principal balance of the Senior Secured Notes;

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 condensed consolidated statements of operations and comprehensive loss.

As of September 30, 2020, the remaining unamortized deferred financing costs were $19,817.

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 have used a portion of the proceeds received to extinguish the Term Loan Facility (defined below).

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 condensed 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 condensed 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.

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 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, but excluding assets used in connection with, related to, appurtenant to, or affecting the pipeline used to supply natural gas to the CHP Plant, and related receivables and assets, and the proceeds were 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 condensed 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.

The Company may redeem the 2025 Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral.

The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications.

The 2025 Notes also provide for customary events of default and prepayment provisions.

We used a portion of the net cash proceeds received from the 2025 Notes to repay in full the outstanding principal and interest of all of our then existing debt facilities.

In connection with the issuance of the 2025 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 2025 Notes on the condensed consolidated balance sheets;

unamortized deferred financing costs related to lenders in our prior credit agreement that participated in the 2025 Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes.

As a portion of the repayment of the prior credit agreement was a modification , in the third quarter of 2020 we recorded $ 4,028 of third-party fees in Selling, general and administrative in the condensed 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 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein).

Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,436.

As of March 31, 2021, total remaining unamortized deferred financing costs were $10,201.

On April 12, 2021, the Company issued $1.5 billion of 2026 Notes.

The 2026 Notes bear interest at a rate of 6.50% per annum, payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021.

The 2026 Notes will mature on September 30, 2026 and may be redeemed earlier by the Company, subject to certain “make-whole” premiums.

The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes.

Under the indenture governing the 2026 Notes, the Company and its restricted subsidiaries are limited in the ability to, among other things, incur additional indebtedness or issue certain preferred shares, incur liens that secure indebtedness, make restricted payments, create dividend restrictions and other payment restrictions that affect the Company’s restricted subsidiaries, sell or transfer certain assets, engage in certain transactions with affiliates and merge or consolidate or transfer all or substantially all of the Company’s assets.

Revolving Facility

On April 15, 2021, the Company entered into the Revolving Facility.

The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments).

Letters of credit issued under the $100 million letter of credit sub-facility may be used for general corporate purposes.

The Revolving Facility will mature in 2026, with the potential for the Company to extend the maturity date once in a one-year increment.

Borrowings under the Revolving Facility will bear interest at a per annum rate equal to LIBOR plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and LIBOR plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0.00% LIBOR floor.

Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium.

The obligations under the Revolving Facility are guaranteed by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the Revolving Facility is secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes.

The Revolving Facility contains usual and customary representations and warranties, and usual and customary affirmative and negative covenants.

Off Balance Sheet Arrangements

As of September 30, 2020, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

As of March 31, 2021 and December 31, 2020, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts.

The following table summarizes certain contractual obligations in place as of September 30, 2020:

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)

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Purchase obligations

Operating lease obligations

[1] Includes contractual obligations from October 1, 2020 through December 31, 2020

Lease obligations

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 September 30, 2020.

Purchase obligations

The Company is party to long term supply agreements.

These contracts 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.

In December 2018, the Company entered into a contract with Centrica LNG Company Limited for the purchase of 29 firm cargoes of 1.1 billion gallons of LNG (86.7 million MMBtu) scheduled for delivery between June 2019 and December 2021.

Payment for each cargo is due in advance of each shipment.

In June 2020, we entered into an agreement to terminate our obligation to purchase any additional LNG cargoes from Centrica for the remainder of 2020 in exchange for a cancellation fee of $105 million, which has enabled us to purchase LNG in the open market at prices that are significantly lower than the price we were obligated to pay Centrica to purchase LNG in 2020.

As of September 30, 2020, the Company is committed to purchase 12 remaining cargoes in 2021.

On February 7, 2020, the Company entered into a long-term supply agreement with an established international gas supplier for the purchase of 27.5 TBtu per year of LNG at a price indexed to Henry Hub from January 2022 to January 2030.

The Company currently has two contracts in place for the purchase of feedgas under take-or-pay minimum volume obligations.

These commitments are structured to assure the Miami Facility has uninterrupted supply and the minimum volumes are not expected to be in excess of normal requirements.

Deliveries under these contracts are scheduled between March 2019 and November 2025.

In 2018, the Company entered into a 15-year agreement with an affiliate of Chesapeake Energy Corporation for gas supply to our Pennsylvania Facility.

The terms of the agreement are subject to certain conditions precedent under our control before the agreement is effective.

These conditions have not yet been met, and as such, this commitment is excluded from the table above.

Operating lease obligations

Future fixed lease payments under non-cancellable operating leases, inclusive of fixed lease payments for renewal periods the Company is reasonably certain will be exercised, are noted in the above table.

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.

The Company’s lease obligations are primarily related to LNG vessel time charters, marine port leases, office space and a land lease.

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.

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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.

Office space includes a space shared with affiliated companies in New York with a lease terms of up to 38 months and an office space in downtown Miami with a lease term of 84 months.

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 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

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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.

Our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, 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.

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For our operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the condensed 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-fired 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.

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We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.

Our business model requires investments in infrastructure often concurrently with our customers’ investments in power generation or other assets to utilize LNG.

Our costs to transport and store LNG are based upon our customers’ contractual commitments once their assets are fully operational.

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 customers’ operations and our locations allow us to expand to additional opportunities within existing markets.

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 a long-term LNG supply agreement to purchase 27.5 TBtus annually beginning in 2022 at prices that are expected to be significantly lower than inventory purchased under our contract with our current supplier.

Further, we will take advantage of the current market pricing for LNG to supply our operations for the remainder of 2020, resulting in an overall lower average cost of LNG.

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 decreases throughout 2019 and 2020.

Due to the decline in LNG prices, we executed four 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 the 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.

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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.

Based on the essential nature of the services we provide to support power generation facilities, our development projects have not been significantly impacted by responses to the COVID-19 pandemic to date.

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.

The COVID-19 pandemic has also significantly impacted energy markets, and the price of oil 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, we measure whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value.

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.

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Share-based compensation

We estimate the fair value of RSUs and performance stock units 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.

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.

Current expected credit losses

During the third quarter, the Company adopted ASU 2016-13, Financial Instruments – Credit Losses (Topic 326):

Disclosure Framework – Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which requires financial assets measured at amortized cost basis, which include trade and other receivables, contracts assets, and finance lease receivables, be presented net of an allowance for current expected credit losses.

We estimate expected credit losses based on relevant information about the current credit quality of our customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectability of the reported amount.

Our estimate includes consideration of the credit quality of our customers along with the expected default and recovery rates for bonds with similar ratings and terms as the respective financial assets.

As of March 31, 2021, 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

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis