UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the year ended December 31, 2020

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to_______

Commission File Number:001-38790

New Fortress Energy Inc.

(Exact Name of Registrant as Specified in its Charter)

Delaware		83-1482060
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

111 W. 19th Street, 8th Floor New York, NY		10011
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (516) 268-7400

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered on which registered
Class A common stock	NFE	NASDAQ Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐	Accelerated filer ☒
Non-accelerated filer ☐	Smaller reporting company ☐
	Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed as of June 30, 2020 (the last business day of the registrant’s most recently completed second fiscal quarter), based on the closing price of the Class A shares on the Nasdaq Global Select Market, was $417.4 million.

At March 15, 2021, the registrant had 175,958,649 shares of Class A common stock outstanding.

Documents Incorporated by Reference:

Portions of the registrant’s definitive proxy statement for the registrant’s 2021 annual meeting, to be filed within 120 days after the close of the registrant’s fiscal year, are incorporated by reference into Parts II and III of this Annual Report on Form 10-K.

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GLOSSARY OF TERMS			1
CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS			2
PART I			3
	Items 1 and 2.	Business and Properties	3
	Item 1A.	Risk Factors	14
	Item 1B.	Unresolved Staff Comments.	61
	Item 3.	Legal Proceedings.	61
	Item 4.	Mine Safety Disclosures.	61
PART II			62
	Item 5.	Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.	62
	Item 6.	Selected Financial Data.	64
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	65
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	80
	Item 8.	Financial Statements and Supplementary Data.	80
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	80
	Item 9A.	Controls and Procedures.	80
	Item 9B.	Other Information.	81
PART III			82
	Item 10.	Directors, Executive Officers and Corporate Governance.	82
	Item 11.	Executive Compensation	82
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	82
	Item 13.	Certain Relationships and Related Transactions, and Director Independence.	82
	Item 14.	Principal Accounting Fees and Services.	82
PART IV			83
	Item 15.	Exhibits, Financial Statement Schedules.	83
	Item 16.	Form 10-K Summary	85
	SIGNATURES		86

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GLOSSARY OF TERMS

As commonly used in the liquefied natural gas industry, to the extent applicable and as used in this Annual Report on Form 10-K (“Annual Report”), the terms listed below have the following meanings:

ADO	automotive diesel oil

Bcf/yr	billion cubic feet per year

Btu	the amount of heat required to raise the temperature of one avoirdupois pound of pure water from 59 degrees Fahrenheit to 60 degrees Fahrenheit at an absolute pressure of 14.696 pounds per square inch gage

CAA	Clean Air Act

CERCLA	Comprehensive Environmental Response, Compensation and Liability Act

CWA	Clean Water Act

DOE	U.S. Department of Energy

DOT	U.S. Department of Transportation

EPA	U.S. Environmental Protection Agency

FTA countries	countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas

GAAP	generally accepted accounting principles in the United States

GHG	greenhouse gases

GSA	gas sales agreement

Henry Hub	a natural gas pipeline located in Erath, Louisiana that serves as the official delivery location for futures contracts on the New York Mercantile Exchange

ISO container	International Organization of Standardization, an intermodal container

LNG	natural gas in its liquid state at or below its boiling point at or near atmospheric pressure

MMBtu	one million Btus, which corresponds to approximately 12.1 LNG gallons

mtpa	metric tons per year

MW	megawatt. We estimate 2,500 LNG gallons would be required to produce one megawatt.

NGA	Natural Gas Act of 1938, as amended

non-FTA countries	countries without a free trade agreement with the United States providing for national treatment for trade in natural gas and with which trade is permitted

OPA	Oil Pollution Act

OUR	Office of Utilities Regulation (Jamaica)

PHMSA	Pipeline and Hazardous Materials Safety Administration

PPA	power purchase agreement

SSA	steam supply agreement

TBtu	one trillion Btus, which corresponds to approximately 12,100,000 LNG gallons

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CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K for the year ended December 31, 2020 (this “Annual Report”) contains forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this Annual Report other than historical information are forward-looking statements that involve known and unknown risks and relate to future events, our future financial performance or our projected business results. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “projects,” “targets,” “potential” or “continue” or the negative of these terms or other comparable terminology. Such forward-looking statements are necessarily estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. While it is impossible to identify all such factors, factors that could cause actual results to differ materially from those estimated by us include:

•	our limited operating history;

•	loss of one or more of our customers;

•

inability to procure LNG on a fixed-price basis, or otherwise to manage LNG price risks, including hedging arrangements;

•	the completion of construction on our LNG terminals, facilities, power plants or Liquefaction Facilities and the terms of our construction contracts for the completion of these assets;

•	cost overruns and delays in the completion of one or more of our LNG terminals, facilities, power plants or Liquefaction Facilities, as well as difficulties in obtaining sufficient financing to pay for such costs and delays;

•	our ability to obtain additional financing to effect our strategy;

•	Each of the Proposed Mergers is subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all, and we, Hygo and GMLP are each subject to business uncertainties and contractual restrictions while the Proposed Mergers are pending;

•	After the Proposed Mergers, we may be unable to successfully integrate the businesses and realize the anticipated benefits of the Proposed Mergers;

•	failure to produce or purchase sufficient amounts of LNG or natural gas at favorable prices to meet customer demand;

•	hurricanes or other natural or manmade disasters;

•	failure to obtain and maintain approvals and permits from governmental and regulatory agencies;

•	operational, regulatory, environmental, political, legal and economic risks pertaining to the construction and operation of our facilities;

•	inability to contract with suppliers and tankers to facilitate the delivery of LNG on their chartered LNG tankers;

•	cyclical or other changes in the demand for and price of LNG and natural gas;

•	failure of natural gas to be a competitive source of energy in the markets in which we operate, and seek to operate;

•	competition from third parties in our business;

•	inability to re-finance our outstanding indebtedness;

•	changes to environmental and similar laws and governmental regulations that are adverse to our operations;

•	inability to enter into favorable agreements and obtain necessary regulatory approvals;

•	the tax treatment of us or of an investment in our Class A shares;

•	the completion of the Exchange Transactions (as defined below);

•	a major health and safety incident relating to our business;

•	increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel;

•	risks related to the jurisdictions in which we do, or seek to do, business, particularly Florida, Jamaica, Brazil and the Caribbean; and

•	other risks described in the “Risk Factors” section of this Annual Report.

When considering forward-looking statements, you should keep in mind the risks set forth under “Item 1A. Risk Factors” and other cautionary statements included in this Annual Report. The cautionary statements referred to in this section also should be considered in connection with any subsequent written or oral forward-looking statements that may be issued by us or persons acting on our behalf. We undertake no duty to update these forward-looking statements, even though our situation may change in the future. Furthermore, we cannot guarantee future results, events, levels of activity, performance, projections or achievements.

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PART I

Items 1 and 2.

Business and Properties

Unless the context otherwise requires, references in this Annual Report to the “Company,” “NFE,” “we,” “our,” “us” or like terms refer to New Fortress Energy Inc. and its subsidiaries. When used in a historical context, “our,” “us,” “we” or like terms refer to (i) prior to our conversion from a limited liability company to a corporation, New Fortress Energy LLC and its subsidiaries and (ii) following the conversion from a limited liability company to a corporation, New Fortress Energy Inc. and its subsidiaries. When used in a historical context that is prior to the completion of NFE’s initial public offering (“IPO”), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Holdings LLC, a Delaware limited liability company (“New Fortress Energy Holdings”), our predecessor for financial reporting purposes.

Overview

We are a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs. We deliver targeted energy solutions to customers around the world, thereby reducing their energy costs and diversifying their energy resources, while also reducing pollution and generating compelling margins. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading carbon emission-free independent power providing companies. We discuss this important goal in more detail below under “Toward a Carbon-Free Future.”

We deliver targeted energy solutions by employing an integrated LNG supply and delivery model:

LNG Supply and Liquefaction - We supply LNG to our customers, typically by entering into long-term LNG supply contracts, which are generally based on an index such as Henry Hub plus an additional fee. We have successfully capitalized on current market conditions to secure long-term LNG contracts, which are also based on Henry Hub plus an additional fee, with attractive terms. In addition, we supply LNG to our customers from open market purchases and LNG from our existing liquefaction and storage facility in Miami, Florida (the “Miami Facility”).

Shipping - We have long-term charters for liquefied natural gas carriers (“LNGCs”) and floating storage and regasification units (“FSRUs”). These assets transport LNG from ports to our downstream facilities and gasify LNG for ultimate delivery to our customers.

Facilities - Through our network of current and planned downstream facilities and logistics assets, we are strategically positioned to deliver gas and power solutions to our customers seeking either to transition from environmentally dirtier distillate fuels such as automotive diesel oil (“ADO”) and heavy fuel oil (“HFO”) or to purchase natural gas to meet their current fuel needs.

Our Business Model

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 shipping, logistics, facilities and conversion or development of natural gas-fired power generation. While historically, natural gas procurement or liquefaction, transportation, regasification and power generation have been financed separately, the segregation of such projects has inhibited the development of natural gas-fired power in many developing countries. In executing our business model, we have the capability to build or arrange any necessary infrastructure ourselves without reliance on multilateral financing sources or traditional project finance structures, so that we maintain our strategic flexibility.

We currently conduct our operations at our LNG storage and regasification facility at the Port of Montego Bay, Jamaica (the “Montego Bay Facility”), our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility” and, together with the Montego Bay Facility, the “Jamaica Facilities”), our landed micro-fuel handling facility in San Juan, Puerto Rico (the “San Juan Facility”) and at our Miami Facility. In addition, we are currently developing facilities in Mexico, Nicaragua and Ireland, as described below in more detail. We are in active discussions with additional customers in multiple regions around the world who may have significant demand for additional LNG, although there can be no assurance that these discussions will result in additional contracts or the terms of such contracts or that we will be able to achieve our target pricing or margins.

Our Facilities

Downstream, we have six facilities operational or under active development. Our facilities position us to acquire and supply LNG to customers in a number of attractive markets around the world.

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We look to build facilities in locations where the need for LNG is significant. In these markets, we first seek to identify and establish “beachhead” target markets for the sale of LNG, natural gas or natural gas-fired power. We then seek to convert and supply natural gas to additional power customers. Finally, our goal is to expand within the market by supplying additional industrial and transportation customers.

We currently have three operational facilities and three under active development, as described below. We design and construct facilities to meet the supply and demand specifications of our current and potential future customers in the applicable region. Our facilities currently operating or under development are expected to be capable of receiving between 740,000 and 6 million gallons of LNG (61,000 and 500,000 MMBtu) per day depending upon the needs of our customers and potential demand in the region. Set forth below is additional detail regarding each such facility:

Montego Bay, Jamaica - Our Montego Bay Facility commenced commercial operations in October 2016. The Montego Bay Facility 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. It supplies natural gas to the 145 MW power station operated by Jamaica Public Service Company Limited (“JPS”) pursuant to a long-term contract for natural gas equivalent to approximately 310,000 gallons of LNG (25,600 MMBtu) per day. The Montego Bay Facility also supplies numerous on-island industrial users with natural gas or LNG pursuant to numerous offtake contracts of various durations, some of which contain take-or-pay provisions. We have total aggregate contracted volumes of approximately 405,000 gallons of LNG (33,470 MMBtu) per day at our Montego Bay Facility with a weighted average remaining contract length of 15.3 years as of December 31, 2020. We have the ability to service other potential customers with the excess capacity of the Montego Bay Facility, and we are seeking to enter into long-term contracts with new customers for such purposes. We deliver LNG to the Montego Bay Facility via small LNGCs.

Old Harbour, Jamaica - Our Old Harbour Facility commenced commercial operations in June 2019. It is capable of processing approximately 6 million gallons of LNG (500,000 MMBtu) per day. The Old Harbour Facility is supplying gas to a new 190 MW Old Harbour gas-fired power plant (the “Old Harbour Power Plant”) operated by South Jamaica Power Company Limited (“SJPC”) pursuant to a long-term contract for natural gas equivalent to approximately 380,000 gallons of LNG (31,400 MMBtu) per day. The Old Harbour Facility is also supplying gas to the dual-fired combined heat and power (“CHP”) facility in Clarendon, Jamaica (the “CHP Plant”) that we constructed and which commenced commercial operations on March 3, 2020. See “—Our Current Customers—Jamalco CHP Plant.” We have total aggregate contracted volumes of approximately 760,000 gallons of LNG (62,810 MMBtu) per day at our Old Harbour Facility with an average contract length of 18.7 years as of December 31, 2020. We have the ability to service other potential customers with the excess capacity of the Old Harbour Facility, and we are seeking to enter into long-term contracts with new customers for such purposes. The Old Harbour Facility is an offshore facility with storage and regasification equipment provided via FSRU. The offshore design eliminates the need for expensive storage tanks and permanent, onshore infrastructure.

San Juan, Puerto Rico – Our San Juan Facility became fully operational in the third quarter of 2020. It is designed as a landed micro-fuel handling facility located in the Port of San Juan, Puerto Rico. We have leased the land under a long-term agreement. The San Juan Facility has multiple truck loading bays to provide LNG to on-island industrial users. In addition, it supplies natural gas to Units 5 and 6 of the San Juan Combined Cycle Power Plant (the “San Juan Power Plant”), which are owned and operated by the Puerto Rico Electric Power Authority, a public instrumentality of the government of Puerto Rico (“PREPA”). We converted Units 5 and 6, which together have a capacity of 440 MW, to use natural gas as fuel and expect to supply both Units 5 and 6 with approximately 26 TBtu of natural gas per year, which equals approximately 863,000 gallons of LNG (70,000 MMBtu) per day.

La Paz, Baja California Sur, Mexico - We were awarded a public tender to build, own and operate an LNG receiving facility (the “La Paz Facility”) on July 18, 2018. Our La Paz Facility is currently under development and is expected to commence commercial operations in the second quarter of 2021. It is being designed as an LNG receiving facility located at the Port of Pichilingue in Baja California Sur, Mexico, where LNG will be delivered via ISO containers on an offshore supply vehicle from a mothership moored nearby. 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 operate, which may be increased to approximately 350,000 gallons of LNG (29,000 MMBtu) per day for up to 135 MW of power. In addition, we were declared the winner of a bid with CFEnergia for the supply of natural gas to power plants located at Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day and are in the process of finalizing definitive agreements for this supply. Similarly, we expect that we will use the La Paz Facility to facilitate the supply of approximately 200,000 gallons of LNG (16,500 MMBtu) per day to regional industrial users and hotels.

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Puerto Sandino, Nicaragua - We have entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, and under the terms of such agreement we expect to provide approximately 700,000 gallons of LNG (57,500 MMBtu) per day. We are designing and developing an offshore liquefied natural gas receiving and storage facility off the coast of Puerto Sandino, Nicaragua as well as an onshore regasification facility (the “Puerto Sandino Facility”). The Puerto Sandino Facility is expected to supply gas to a new approximately 300 MW natural gas-fired power plant (the “Nicaragua Power Plant”) that we will own and operate.

Shannon, Ireland - We have entered into an agreement to purchase all of the ownership interests in a project company that owns the rights to develop and operate an LNG facility and a CHP plant on the Shannon Estuary near Ballylongford, Ireland. We intend for this facility to include a storage facility with onshore regasification equipment and pipeline connection into the distribution system of Gas Networks Ireland, Ireland’s national gas network (the “Ireland Facility” and, together with the Jamaica Facilities, the San Juan Facility, the La Paz Facility and the Puerto Sandino Facility, our “Facilities”). We are in the process of obtaining final planning permission from the Commission for Regulation of Utilities in Ireland and we intend to begin construction of the Ireland Facility after we have obtained such permission and secured contracts with downstream customers with volumes sufficient to support the development.

Our LNG Supply Contracts and Liquefaction Assets

LNG Supply Contracts

In December 2018, the Company entered into a contract with Centrica LNG Company Limited (“Centrica”) 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. In June 2020, we terminated our obligation to purchase any additional LNG cargoes for the remainder of 2020 in exchange for a one-time payment 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 to Centrica to purchase LNG in 2020.

In 2020, the Company entered into four supply agreements for the purchase of approximately 415 TBtu of LNG between 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.

Liquefaction Assets

We constructed the Miami Facility, which commenced full commercial operations in 2016, in under 12 months at a cost to build of approximately $70 million. The Miami Facility has one liquefaction train, with liquefaction production capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) per day and was 97.5% dispatchable during 2020. The Miami Facility also has three LNG storage tanks, with total capacity of approximately 1,000 cubic meters. The Miami Facility also includes two separate LNG transfer areas capable of serving both truck and rail. For the fiscal year ended December 31, 2020, we delivered approximately 35,000 gallons of LNG (2,900 MMBtu) per day from the Miami Facility pursuant to long-term, take-or-pay contracts.

We are currently evaluating the timing of the development of a natural gas liquefaction plant on land we have purchased in the Marcellus area of Pennsylvania (the “Pennsylvania Facility”, and together with the Miami Facility, the “Liquefaction Facilities”). In December 2019, PHMSA granted a special permit to one of our subsidiaries to ship LNG by rail, which would allow us to transport the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels.

Our Current Customers

Our downstream customers are, and we expect future customers to be, a mix of power, transportation and industrial users of natural gas and LNG. We seek to substantially reduce our customers’ fuel costs while providing them with a cleaner-burning, more environmentally friendly fuel source. We also intend to sell power and steam directly to some of our customers. In addition, we provide development services to some customers for the conversion or development of natural gas-fired power generation in connection with long-term agreements to supply natural gas or LNG to the customer.

We seek to enter into long-term, take-or-pay contracts to deliver natural gas or LNG. Pricing for any particular customer depends on the size of the customer, purchased volume, the customer’s credit profile, the complexity of the delivery and the infrastructure required to deliver it.

A limited number of customers currently represent a large percentage of our income. For the twelve months ended December 31, 2020, revenue from three significant customers constituted 88% of total revenues.

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We have several contracts with government affiliated entities in Jamaica, including contracts with JPS and SJPC (as defined below and collectively, the “Jamaica GSAs”) and with a governmental instrumentality in Puerto Rico, PREPA. The Jamaica GSAs represent approximately 50% of Jamaica’s installed power capacity and sales of approximately 955,000 gallons of LNG (79,000 MMBtu) per day at full commercial operations. The Jamaica GSAs have remaining terms of approximately 18.3 years, with mutual options to extend, subject to certain conditions. The aggregate minimum quantities we are required to deliver, and our counterparties are required to purchase, under the Jamaica GSAs initially, total approximately 56,200 MMBtu per day. Additionally, we have a Fuel Sale and Purchase Agreement with PREPA under which we expect PREPA to purchase 863,000 gallons of LNG (70,000 MMBtu) per day.

Bogue Power Plant

We have executed a 22-year agreement to supply JPS’s 145 MW Bogue power plant (the “Bogue Power Plant”) in Montego Bay, Jamaica with natural gas. The Bogue Power Plant has been converted to run on natural gas as well as ADO as backup fuel.

Old Harbour Power Plant

We have executed an agreement to supply SJPC’s Old Harbour Power Plant in Old Harbour, Jamaica with natural gas and back-up ADO for 20 years. The Old Harbour Power Plant is an approximately 190 MW capacity dual fuel plant owned by SJPC.

Jamalco CHP Plant

We have executed a suite of agreements, including a 20-year SSA to supply a joint venture between General Alumina Jamaica (“GAJ”), a subsidiary of Noble Group, and Clarendon Alumina Production Limited, an entity owned by the Government of Jamaica, with a focus on bauxite mining and alumina production in Jamaica (“Jamalco”) with steam for use in its alumina refinery operations and a 20-year PPA to supply electricity to JPS. The CHP Plant is a 150 MW capacity combined heat and power plant and is fueled by natural gas with the ability to run on ADO as a backup fuel source.

PREPA San Juan Power Plant

On March 5, 2019, we entered into an agreement with PREPA, under which we converted Units 5 and 6 of the San Juan Power Plant to use natural gas, which together have a capacity of 440 MW, and we are supplying natural gas fuel to Units 5 and 6. The natural gas supply agreement has an initial natural gas supply term of 5 years from the beginning of commercial operations of the Units on natural gas and has three separate 5-year extensions that are exercisable at PREPA’s option. We have supplied natural gas for the commissioning of Units 5 and 6 since April 2020.

Nicaragua Power Plant

On February 13, 2020, we entered into a 25-year power purchase agreement to supply electricity to Nicaragua’s electricity distribution companies, and we are in the process of constructing a natural gas-fired power plant with a capacity of approximately 300 MW.

Industrial End-User Sales

We have entered into multiple long-term contracts to sell LNG directly to industrial end-users in Jamaica, Puerto Rico and Mexico. To fulfill the requirements of our end-user customers, we transport LNG through our Facilities (either from our Liquefaction Facilities in the United States or from third parties in market purchases) and deliver such LNG directly to customers’ facilities.

Recent Developments: Hygo and GMLP Acquisitions

Hygo Acquisition

On January 13, 2021, we and Lobos Acquisition Ltd., a Bermuda exempted company and our wholly-owned subsidiary (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “Hygo Merger Agreement”) with Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), pursuant to which, on the terms and subject to conditions set forth in the Hygo Merger Agreement, Hygo Merger Sub will be merged with and into Hygo (the “Hygo Merger”), whereupon the separate corporate existence of Hygo Merger Sub shall cease and Hygo shall continue as the surviving company in the Hygo Merger. As of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.

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The Hygo Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals and other customary closing conditions.

Upon completion of the acquisition of Hygo, we expect to acquire Hygo’s network of existing and development stage marine LNG import facilities, its ownership of interests in existing and development stage large-scale power plants backed by high quality offtakers, and the downstream distribution of LNG from its terminals via marine and onshore logistics to major demand centers in Brazil, each as described in more detail below. In addition, we expect to acquire Hygo’s vessel fleet, which consists of the Golar Nanook, a newbuild FSRU moored and in service at the Sergipe Facility (as defined herein), and two operating LNG carriers, the Golar Celsius and the Golar Penguin, which may be converted into FSRUs.

Sergipe Facility and Sergipe Power Plant. Hygo’s facility located near Aracaju, the state capital of Sergipe, Brazil (the “Sergipe Facility”), commenced commercial operations in March 2020 and is a key component in Brazil’s first private-sector LNG-to-power project. The Sergipe Facility is operated by Centrais Elétricas de Sergipe S.A. (“CELSE”), an entity wholly owned by Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), a 50/50 joint venture between Hygo and Ebrasil Energia Ltda. (“Ebrasil”), an affiliate of Eletricidade do Brasil S.A., one of the largest independent private thermoelectric energy generators in the north and northeast regions of Brazil. The facility’s assets consist of (i) Hygo’s 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 Sergipe Facility is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The terminal is expected 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.

The Sergipe Power Plant, a 1.5 GW combined cycle power plant (the “Sergipe Power Plant”), receives natural gas from the Sergipe Facility through a dedicated 8 kilometer pipeline. Owned by CELSE, the Sergipe Power Plant is the largest natural gas-fired thermal power station in South America and was built to provide electricity on demand throughout the region, particularly during dry seasons when hydropower is unable to meet the growing demand for electricity in the region. Following its bid award in a government power auction in April 2015, CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant is delivering power to 26 committed offtakers, including investment grade counterparties, for a period of 25 years. Hygo anticipates generating incremental earnings through selling merchant power from the Sergipe Power Plant. The sales would be made through CELSE. Hygo can choose to produce merchant power at the Sergipe Power Plant in any period in which power is not being produced pursuant to the PPAs, and sell the power into the electricity grid at spot prices, subject to local regulatory approval.

Hygo also owns 37.5% of Centrais Elétricas Barra dos Coqueiros S.A. (“CEBARRA”), a joint venture with Ebrasil, which owns expansion rights with respect to the Sergipe Power Plant. These rights include 179 acres of land and regulatory permits for up to 3.2 GW of power generation, including the capacity of the Sergipe Power Plant. CEBARRA has obtained all permits and other rights necessary to participate in future government power auctions. Hygo recently entered into a purchase agreement pursuant to which it will indirectly acquire an additional 37.5% interest in CEBARRA; such acquisition is subject to customary closing conditions including receipt of certain regulatory approvals.

Barcarena Facility and Barcarena Power Plant. Hygo is developing a facility in the State of Pará, Brazil (the “Barcarena Facility”). Hygo anticipates that the Barcarena Facility will be anchored by several large-scale industrial and power customer contracts, including a contract with Centrais Elétricas Barcarena S.A. (“CELBA”), a 50/50 joint venture between Hygo and Evolution Power Partners S.A. (“Evolution”). Hygo recently entered into a purchase agreement pursuant to which it will purchase the remaining 50% interest in CELBA from Evolution; such acquisition is subject to customary closing conditions, including receipt of certain regulatory approvals. The Barcarena Facility will consist of an FSRU and associated infrastructure, including mooring and offshore and onshore pipelines. The Barcarena Facility will be capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. The Barcarena Facility is expected to utilize approximately 92,000 MMBtu/d (12% of the facility’s maximum regasification capacity) to service the Barcarena Power Plant upon commencement of operations.

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In October 2019, CELBA 2, Hygo’s joint venture with CELBA, Brazilian Energy Participações S.A. and OAK Participações Ltda. was awarded multiple 25-year PPAs to support the construction of a 605 MW combined cycle thermal power plant to be located in Pará, Brazil and to be supplied by the Barcarena Facility (the “Barcarena Power Plant”). The Barcarena Power Plant will utilize LNG sourced and processed at the Barcarena Facility for the generation of electricity which will be distributed to the national electricity grid. The power project is scheduled to deliver power to nine committed offtakers for 25 years beginning in 2025 in accordance with the PPA contracts awarded by the Brazilian government in October 2019.

Santa Catarina Facility and Pipeline. Hygo is finalizing the process of securing key regulatory and environmental licenses to develop a facility on the southern coast of Brazil, near Santa Catarina (the “Santa Catarina Facility”) that is intended to consist of an FSRU with a processing capacity of approximately 790,000 MMBtu/d and LNG storage capacity of up to 170,000 cubic meters. In addition to the Santa Catarina Facility, Hygo is developing a 31 kilometer, 20 inch pipeline that will connect the Facility to the existing inland Transportadora Brasiliera Boliva (“TBG”) pipeline via an interconnection point in Garuva. The Santa Catarina Facility and associated pipeline is subject to final investment decision.

Partnership with BR Distribuidora. During the first quarter of 2020, Hygo entered into a strategic partnership with Petrobras Distribuidora S.A. (“BR Distribuidora”), Brazil’s leading fuel distribution company, to serve as its exclusive provider of LNG for use in Brazil’s transportation and industrial sectors. Using BR Distribuidora’s 94 distribution centers and 7,600+ fuel stations across Brazil, Hygo expects to leverage its existing infrastructure and LNG supply chain expertise to increase the accessibility of LNG to downstream end-users using a combination of marine and onshore solutions.

Following closing of our acquisition of Pecém and Muricy, we will seek to obtain the necessary approvals from the Agência Nacional de Energia Elétrica (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics in order to develop and 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.

GMLP Acquisition

On January 13, 2021, we entered into an Agreement and Plan of Merger (as it may be amended, supplemented or otherwise modified from time to time, the “GMLP Merger Agreement”) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability company and the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and our wholly-owned subsidiary (“GMLP Merger Sub”) and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales and our wholly-owned subsidiary (“GP Buyer”), pursuant to which, on the terms and subject to the conditions thereof, GMLP Merger Sub will be merged with and into GMLP (the “GMLP Merger” and, together with the Hygo Merger, the “Proposed Mergers”) and GMLP shall continue its existence as the surviving company in the GMLP Merger.

At the effective time of the GMLP Merger (the “GMLP Effective Time”), each common unit representing a limited partner interest in GMLP that is issued and outstanding as of immediately prior to the GMLP Effective Time will automatically be converted into the right to receive $3.55 in cash. At the GMLP Effective Time, each of the incentive distribution rights of GMLP will be canceled and cease to exist, and no consideration shall be delivered in respect thereof. Each 8.75% Series A Cumulative Redeemable Preferred Unit of GMLP issued and outstanding immediately prior to the GMLP Effective Time will be unaffected by the GMLP Merger and will remain outstanding, and no consideration shall be delivered in respect thereof. Each outstanding unit representing a general partner interest of GMLP that is issued and outstanding immediately prior to the GMLP Effective Time will remain issued and outstanding immediately following the GMLP Effective Time. Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General Partner pursuant to a Transfer Agreement dated as of January 13, 2021 for a purchase price of approximately $5 million, which is equivalent to $3.55 per general partner unit of GMLP.

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The GMLP Merger Agreement may be terminated by NFE or GMLP (which, in the case of GMLP, must be approved by GMLP’s Conflicts Committee) under certain circumstances, including, among others, by either NFE or GMLP if the closing of the GMLP Merger has not occurred on or before July 13, 2021, and further provides that, upon termination of the GMLP Merger Agreement under certain circumstances, GMLP may be required to pay NFE a termination fee equal to approximately $9.4 million.

The GMLP Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals, the approval of the GMLP Merger Agreement by the majority of the holders of GMLP common units and other customary closing conditions.

Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs (the Golar Spirit, the Golar Winter, the Golar Freeze, the NR Satu, the Golar Igloo, and the Golar Eskimo), four LNG carriers (the Golar Mazo, the Methane Princess, the Golar Grand, and the Golar Maria) and an interest in a floating liquefaction vessel, the Hilli Episevo (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. GMLP currently owns 50% of the common units of Golar Hilli LLC which owns Golar Hilli Corporation (“Hilli Corp”), the disponent owner of the Hilli. The Hilli is the world’s first converted FLNG vessel. 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.

Financing Commitments

In connection with entering into the each of the Hygo Merger Agreement and the GMLP Merger Agreement, on January 13, 2021 and January 20, 2021, we obtained financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If drawn, the proceeds of such committed financing are expected to be made available under a senior secured bridge term loan facility in an aggregate principal amount of $1.5 billion and a revolving credit facility in an aggregate principal amount of $200 million.

Competition

In marketing LNG and natural gas, we compete for sales of LNG and natural gas primarily with LNG distribution companies who focus on sales of LNG without our integrated approach which includes development services and power. We also compete with a variety of natural gas marketers who may have affiliated distribution partners, including:

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major integrated marketers whose advantages include large amounts of capital and the ability to offer a wide range of services and market numerous products other than natural gas;

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producer marketers who sell natural gas they produce or which is produced by an affiliated company;

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small geographically focused marketers who focus their marketing on the geographic area in which their affiliated distributor operates; and

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aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.

Despite these competitors, we do not expect to experience significant competition for our LNG logistics services with respect to the Facilities to the extent we have entered into fixed GSAs or other long-term agreements we serve through the Facilities. If and when we have to replace our agreements with our counterparties, we may compete with other then-existing LNG logistics companies for these customers.

There are no other liquefaction facilities currently in operation in Southern Florida.

In purchasing LNG, we will compete for supplies of LNG with:

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large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources;

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oil and gas producers who sell or control LNG derived from their international oil and gas properties; and

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purchasers located in other countries where prevailing market prices can be substantially different from those in the United States.

Government Regulation

Our LNG infrastructure is, and operations are, subject to extensive regulation under federal, state and local statutes, rules, regulations and laws, as well as foreign regulations and laws. These laws require, among other things, consultations with appropriate federal, state and other agencies and that we obtain, maintain and comply with applicable permits, approvals and other authorizations for the siting and conduct of our business. These regulatory requirements increase our costs of operations and construction, and failure to comply with such laws could result in consequences such as substantial penalties and/or the issuance of administrative orders to cease or restrict operations until we are in compliance.

DOE Export

The DOE issued orders authorizing us, through our subsidiary, American LNG Marketing LLC or its designee, to export up to a combined total of the equivalent of 60,000 mtpa (approximately 3.02 Bcf/yr) of domestically produced LNG by tanker from the Miami Facility to FTA countries for a 20-year term and to non-FTA countries for a 20-year term under contracts with terms of two years or longer. The 20-year term of the authorizations commenced on February 5, 2016, the date of first export from the Miami Facility. The DOE has also authorized American LNG Marketing LLC or its designee to export LNG from the Miami Facility to FTA and non-FTA countries under short-term (less than two years) agreements or on a spot cargo basis. Any LNG exported under the short-term authorization would be counted toward the quantity authorized under the long-term authorizations. These authorizations from the DOE are only applicable to exports of LNG produced at our Miami Facility, and exports of LNG from a liquefaction facility other than the Miami Facility (such as the Pennsylvania Facility) to FTA and/or non-FTA countries will require us to obtain new authorizations from the DOE.

The DOE issued an order authorizing us, through our subsidiary, NFEnergía LLC, to import LNG from various international sources by vessel at our San Juan Facility up to a total volume equivalent to 80 Bcf of natural gas over the two-year period beginning March 26, 2020. NFEnergía LLC must renew its authorization every two years. Imports of LNG are deemed to be consistent with the public interest under Section 3(c) of the Natural Gas Act (“NGA”) and applications for such imports must be granted without modification or delay.

FERC Authorization

The Federal Energy Regulatory Commission (“FERC”) regulates the siting, construction and operation of “LNG terminals” under NGA Section 3(e). In consultation with our outside counsel and, where appropriate, FERC staff, we have designed and constructed our U.S. facilities so that they do not meet the statutory definition of an “LNG terminal” as interpreted by FERC pursuant to its case law. On June 18, 2020, we received an order from FERC which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. The matter was raised during a FERC open meeting held on January 19, 2021 but was not resolved, is on the agenda during the FERC open meeting to be held on March 18, 2021, and remains pending. We do not know if or when FERC will respond to our reply, or the outcome of any such response.

Pipelines and Hazardous Materials Safety Administration

Many LNG facilities are also subject to regulation by the DOT, through PHMSA; PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of “pipeline facilities,” which PHMSA has defined to include certain LNG facilities that liquefy, store, transfer or vaporize natural gas transported by pipeline in interstate or foreign commerce. PHMSA has promulgated detailed, comprehensive regulations governing LNG facilities under its jurisdiction at Title 49, Part 193 of the United States Code of Federal Regulations. These regulations address LNG facility siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. Variances from these regulations may require obtaining a special permit from PHMSA, the issuance of which is subject to public notice and comment and consultation with other federal agencies, which could result in delays, perhaps substantial in length, to the construction of our facilities where such variances are needed; additionally, PHMSA may condition, revoke, suspend or modify the special permits it issues.

In December 2019, PHMSA granted a special permit to one of our subsidiaries to ship LNG by rail, which would allow us to ship the LNG produced by the Pennsylvania Facility to a port for transloading onto marine vessels. On July 24, 2020, PHMSA issued a final rule authorizing the nationwide transportation of LNG by rail in DOT– 113C120W specification rail tank cars, subject to all applicable requirements and certain additional operational controls. The appeal period for the special permit has expired, although the final rule authorizing nationwide transportation will likely be challenged.

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Environmental Regulation

Our LNG infrastructure and operations are subject to various international, federal, state and local laws and regulations as well as foreign laws and regulations relating to the protection of the environment, natural resources and human health. These laws and regulations may require the installation of controls on emissions and structures to prevent or mitigate any potential harm to human health and the environment or require certain protocols to be in place for mitigating or responding to accidental or intentional incidents at certain facilities. These laws and regulations may also lead to substantial penalties for noncompliance and substantial liabilities for incidents arising out of the operation of our facilities. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial civil and criminal fines and penalties for non-compliance.

Other local laws and regulations, including local zoning laws, critical infrastructure regulations and fire protection codes, may also affect where and how we operate.

The costs of compliance with these requirements are not expected to have a material adverse effect on our business, financial condition or results of operations.

Environmental Regulation in Mexico

Mexican law comprehensively regulates all aspects of the receipt, delivery, storage and re-vaporization of LNG as well as the generation and transmission of electricity in Mexico. Various federal agencies in Mexico regulate these activities, including the Department of Environment and Natural Resources, Department of Communication and Transportation, Energy Regulatory Commission, and the Agency for Safety, Energy & Environment, which issues permits for all activities associated with the use of fossil fuels. State and local agencies also regulate these activities, issuing permits and authorizing the use of property for such purposes. In order to be able to obtain various permits for operations under Mexican law, the project must first complete environmental and social impact analyses according to the requirements of Mexican law. Each such impact analysis is subject to further appeal. Mexican law allows the governmental entities and, in certain cases, individuals to pursue claims against violators of environmental laws or permits issued pursuant to such laws. In March 2021, an amendment to the Mexican Power Industry Law (Ley de la Industria Electrica) was published which would reduce the dispatch priority of privately-owned power plants compared to state-owned power plants in Mexico. The amendment is being challenged as unconstitutional, and a judge recently awarded a temporary injunction halting the implementation of the amendment. However, if the amendment is enforced against us, it could negatively affect our plant's dispatch and our revenue and results of operations.

Environmental Regulation in Jamaica

Our operations in Jamaica are governed by various environmental laws and regulations. These laws and regulations are largely implemented through the National Environment and Planning Agency and cover discharges of pollutants, regulation of air emissions, discharges and treatment of wastewater, storage of fuels, and responses to industrial emergencies involving hazardous materials. The level of environmental regulation in Jamaica has increased in recent years, and the enforcement of environmental laws is becoming more stringent. Compliance has not had a material adverse effect on our business, operations, or financial condition. Jamaica is also in the process of developing a law to govern the receipt, storage, processing and distribution of natural gas, as well as requirements for the licensing, construction, and operation of natural gas facilities and transportation.

Environmental Regulation in Nicaragua

The regulation of activities with the potential to impact the environment in Nicaragua are largely regulated by the Natural Resource and Environment Ministry. Nicaragua regulates many areas of environmental protection. In order to obtain various permits for operations, a project must complete environmental and social impact analyses according to Nicaraguan law. While Nicaragua does not currently have any legislation specifically addressing the receipt, handling, and distribution of natural gas, such laws may be passed in future.

Environmental Regulation in Ireland

LNG deliveries, storage, regasification and use are extensively regulated in Ireland. Ireland regulates these operations at a national and local level through organic legislation and an array of permits. Ireland’s National Planning Board is the primary regulator for planning and construction, while the Irish Environmental Protection Agency issues industrial emissions licenses that regulate environmental and operational permitting. Safety regulation in Ireland is regulated pursuant to the Control of Major Accidents regime, which sets out various safety criteria that an LNG facility must meet. We are in the process of applying for all necessary permits to build and complete the Ireland Facility. The issuance of many of these permits will be subject to administrative or judicial challenges, including by non-governmental groups that act on behalf of citizens. For example, in September 2018, an Irish non-governmental organization filed a judicial challenge to the extension of a planning permission associated with our Ireland Facility. In a February 2019 written decision arising out of this judicial challenge, Ireland’s High Court referred several questions relating to the extensions to the European Court of Justice. In February 2020, the European Parliament voted to retain a group of energy infrastructure projects as eligible for EU funding, including the Ireland Facility and broader Shannon LNG project. However, this decision may face further challenges and while this judicial review proceeds, we intend to file for a new planning permission that, if approved, would replace the permission whose extension is currently under challenge. We intend to begin construction of the Ireland Facility after we have obtained a replacement planning permission (or, if earlier, received a favorable resolution to the challenge to the extension of our existing permission) and secured contracts with downstream customers for volumes that are sufficient to support the development.

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U.S. and International Maritime Regulations of LNG Vessels

The International Maritime Organization (“IMO”) is the United Nations agency that provides international regulations governing shipping and international maritime trade. The requirements contained in the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”) promulgated by the IMO govern the shipping of our LNG cargoes and the operations of any vessels we use in our operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a policy for safety and environmental protection setting forth instructions and procedures for operating its vessels safely and also describing procedures for responding to emergencies.

Vessels that transport gas, including LNGCs, are also subject to regulation under various international programs such as the International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk (the “IGC Code”) published by the IMO. The IGC Code provides a standard for the safe carriage of LNG and certain other liquid gases by prescribing the design and construction standards of vessels involved in such carriage, and includes specific air emissions limits, including on sulfur oxide and nitrogen oxide emissions from ship exhausts.

We contract with leading vessel providers in the LNG industry and look to them to ensure that each of our chartered vessels is in compliance with applicable international and in-country requirements. Nevertheless, the IMO continues to review and introduce new regulations and it is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.

Local Partners

One of our subsidiaries, Atlantic Distribution Holdings SRL, has entered into a partnership framework agreement (the “PFA”), with DevTech Environment Limited (“DevTech”). We have partnered with DevTech to pursue strategic investment opportunities related to energy, transportation and infrastructure projects in Jamaica with a total projected cost of development, construction or acquisition of no more than $5 million per project.

Pursuant to the terms of the PFA, when we make an investment related to services provided by DevTech, DevTech will receive 10% of the equity capital in the new investment in exchange for a capital contribution in that proportion. In addition, DevTech will receive profits interests entitling DevTech to 5% of all future distributions once the parties have received a return on the investment equal to their capital contributions. Certain of our subsidiaries have entered into a suite of agreements pursuant to which DevTech became a part owner of our subsidiary NFE North Distribution Limited and received economic interests substantially equivalent to those set forth in the PFA.

Suppliers and Working Capital

We expect to continue to supply our downstream customers with LNG and natural gas sourced from a combination of long-term, LNG contracts with attractive terms, purchases on the open market, and from our Miami Facility.

Due to the nature of our business, we currently carry significant amounts of LNG inventory to meet delivery requirements of customers and assure ourselves of a continuous allotment of goods from suppliers.

Seasonality

Our operations can be affected by seasonal weather, which can temporarily affect our revenues, the delivery of LNG and the construction of our facilities. For example, activity in the Caribbean is often lower during the North Atlantic hurricane season of June through November, and following a hurricane, activity may decrease further as there may be business interruptions as a result of damage or destruction to our facilities or the countries in which we operate. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. In addition, severe winter weather in the Northeast United States may impact the construction of our Pennsylvania Facility and affect the delivery of feedgas to the facility or LNG to and from ports in the region, among other things. Severe weather in Ireland, the Caribbean, Central America or Southern or Western Africa may also delay completion of our Facilities under development and related infrastructure.

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Our Insurance Coverage

We maintain customary insurance coverage for our business and operations. Our domestic insurance related to property, equipment, automobile, general liability and workers’ compensation is provided through policies customary for the business and exposures presented, subject to deductibles typical in the industry. Internationally, we also maintain insurance related to property, equipment, automobile, marine, pollution liability, general liability and the portion of workers’ compensation not covered under a governmental program.

We maintain property insurance, including named windstorm and flood, related to the operation of the Miami Facility, San Juan Facility and the Jamaica Facilities and builders risk insurance at our Facilities under development.

Human Capital

We had 231 full-time employees as of December 31, 2020. We depend upon our skilled workforce to manage, operate and plan for our business. Recruitment and retention of talent accross our company enables growth and innovation accross a multitude of corporate initiatives, and this is one of our top priorities.

Property

We lease space for our offices in New York, New York, Miami, Florida and in other regions in which we operate. We own the properties on which our Pennsylvania Facility will be located. Additionally, the properties on which our Facilities, the CHP Plant and Miami Facility are located are generally subject to long-term leases and rights-of-way. Our leased properties are subject to various lease terms and expirations.

Formation Transactions and Structure

NFE was formed as a Delaware limited liability company by New Fortress Energy Holdings on August 6, 2018. NFE’s initial public offering closed on February 4, 2019 (the “IPO”). On August 7, 2020, the Company converted New Fortress Energy LLC (“NFE LLC”) from a Delaware limited liability company to a Delaware corporation named New Fortress Energy Inc. (the “Conversion”). Since the IPO, NFE LLC had been a corporation for U.S. federal tax purposes, and converting NFE LLC from a limited liability company to a corporation had no effect on the U.S. federal tax treatment of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately prior to the Conversion were converted into one issued and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of the Company (“Class A common stock”). Class A shares shown on the Company’s consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity.

On June 3, 2020, the Company entered into a mutual agreement (the “Mutual Agreement”) with the members holding the majority voting interest in New Fortress Energy Holdings (“Exchanging Members”) and NFE Sub LLC, a wholly-owned subsidiary of NFE. Pursuant to the Mutual Agreement, the Exchanging Members agreed to deliver a block redemption notice in accordance with the Amended and Restated Limited Liability Company Agreement of NFI LLC (the “NFI LLCA”) with respect to all of the NFI LLC Units, together with an equal number of Class B shares of NFE, that such Exchanging Members indirectly own as members of New Fortress Energy Holdings. Pursuant to the Mutual Agreement, NFE agreed to exercise the Call Right (as defined in the NFI LLCA), pursuant to which NFE would acquire such NFI LLC Units and such Class B shares in exchange for Class A shares of NFE (the “Exchange Transactions”). The Exchange Transactions were completed on June 10, 2020. In connection with the closing of the Exchange Transactions, NFE issued 144,342,572 Class A shares in exchange for an equal number of NFI LLC Units, together with an equal number of Class B shares of NFE. Following the completion of the Exchange Transactions, NFE owns all of the NFI LLC Units directly or indirectly and no Class B shares remain outstanding.

Toward a Carbon-Free Future

As we work to reduce emissions for our customers around the world, our long-term goal is to be one of the world’s leading providers of carbon-free energy. Today, we believe that natural gas remains the most cost-effective and environmentally-friendly complement for intermittent renewable energy, aiding the growth of these technologies. Over time, we believe that low-cost hydrogen will play an increasingly significant role as a carbon-free fuel to support renewables and displace fossil fuels across power, transportation and industrial markets. We formed a division, which we call Zero, to evaluate promising technologies and pursue initiatives that will position us to capitalize on this emerging industry. As part of our hydrogen initiative, in October 2020, we announced our intention to partner with Long Ridge Energy Terminal and GE Gas Power to transition a power plant to be capable of burning 100% green hydrogen over the next decade.

Within Zero, we are building two businesses that will look to develop commercially viable pathways to scale low-cost, emissions-free hydrogen. Zero Blue will focus on innovative technologies that are capable of capturing and sequestering nearly all carbon emissions while producing low-cost hydrogen from carbon-based resources like natural gas and coal.

Zero Green will aim to use innovative, cost-effective water-splitting technologies powered by renewable energy to produce emissions-free hydrogen. We made our first hydrogen-related investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost green hydrogen production technology.

Available Information

We are required to file or furnish any annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The SEC maintains an internet website that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file with the SEC, including this Annual Report, at www.sec.gov.

We also make available free of charge through our website, www.newfortressenergy.com, our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report.

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Item 1A.

Risk Factors

An investment in our Class A common stock involves a high degree of risk. You should carefully consider the risks described below. If any of the following risks were to occur, the value of our Class A common stock could be materially adversely affected or our business, financial condition and results of operations could be materially adversely affected and thus indirectly cause the value of our Class A common stock to decline. Additional risks not presently known to us or that we currently deem immaterial could also materially affect our business and the value of our Class A common stock. As a result of any of these risks, known or unknown, you may lose all or part of your investment in our Class A common stock. The risks discussed below also include forward-looking statements, and actual results may differ substantially from those discussed in these forward-looking statements. See “Cautionary Statement on Forward-Looking Statements”.

References to “NFE,” the “Company,” “we,” “us,” “our” and similar terms in this section refer to NFE Inc. and its subsidiaries, including, if the Hygo Merger has closed, Hygo and its subsidiaries, and including, if the GMLP Merger has closed, GMLP and its subsidiaries. References to “Hygo” and “GMLP”, respectively, in this section, refer to Hygo and GMLP and their respective subsidiaries prior to the applicable Proposed Merger, and refer to Hygo and GMLP and their respective subsidiaries, along with the Company and its subsidiaries, following the applicable Proposed Merger.

Summary Risk Factors

Some of the factors that could materially and adversely affect our business, financial condition, results of operations or prospects include the following:

Risks Related to the Proposed Mergers

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Each of the Proposed Mergers is subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all, and we, Hygo and GMLP are each subject to business uncertainties and contractual restrictions while the Proposed Mergers are pending;

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After the Proposed Mergers, we may be unable to successfully integrate the businesses and realize the anticipated benefits of the Proposed Mergers;

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We may not have discovered undisclosed liabilities of either Hygo or GMLP during our due diligence process;

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We expect to incur a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger as a result of the consummation of the Proposed Mergers;

Risks Related to Our Business

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We have not yet completed contracting, construction and commissioning for all of our Facilities and Liquefaction Facilities and there can be no assurance that our Facilities or Liquefaction Facilities will operate as expected or at all;

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We may experience time delays, unforeseen expenses and other complications while developing our projects;

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We may not be profitable for an indeterminate period of time;

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Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results;

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Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long term contracts that we have entered into or will enter into in the near future;

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Operation of our LNG infrastructure and other facilities that we may construct involves significant risks;

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The operation of the CHP Plant and any other power plants involves particular, significant risks;

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Information technology failures and cyberattacks could affect us significantly;

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Our insurance may be insufficient to cover losses that may occur to our property or result from our operations;

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We are unable to predict the extent to which the global COVID-19 pandemic will negatively adversely affect our operations financial performance, or ability to achieve our strategic objectives, or our customers and suppliers;

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We perform development or construction services from time to time which are subject to a variety of risks unique to these activities;

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We may not be able to purchase or receive physical delivery of natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations to customers;

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Failure of LNG to be a competitive source of energy in the markets in which we operate could adversely affect our expansion strategy;

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Our current lack of asset and geographic diversification;

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Failure to obtain and maintain permits, approvals and authorizations from governmental and regulatory agencies on favorable terms with respect to the design, construction and operation of our facilities could impede operations and construction;

Risks Related to the Jurisdictions in Which We Operate

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We are currently highly dependent upon economic, political and other conditions and developments in the Caribbean, particularly Jamaica, Puerto Rico and the other jurisdictions in which we operate;

Risks Related to Hygo Business Activities

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Hygo’s Sergipe Facility has commenced commercial operations and Hygo’s other planned facilities are in various stages of contracting, construction, permitting and commissioning;

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Hygo’s cash flow will be dependent upon the ability of its operating subsidiaries and joint ventures to make cash distributions to Hygo, the amount of which will depend on various factors;

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Hygo may not be able to fully utilize the capacity of its facilities;

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Hygo is currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil;

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Hygo’s sale and leaseback agreements contain restrictive covenants that may limit its liquidity and corporate activities;

Risks Related to GMLP Business Activities

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GMLP currently derives all of its revenue from a limited number of customers and will face substantial competition in the future;

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GMLP’s equity investment in Golar Hilli LLC may not result in anticipated profitability or generate cash flow sufficient to justify its investment. In addition, this investment exposes GMLP to risks that may harm its business;

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GMLP may experience operational problems with its vessels that reduce revenue and increase costs;

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GMLP may be unable to obtain, maintain, and/or renew permits necessary for its operations or experience delays in obtaining such permits;

Risks Related to Ownership of Our Class A Common Stock

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A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders;

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The declaration and payment of dividends to holders of our Class A common stock is at the discretion of our board of directors and there can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all; and

Risks Related to the Proposed Mergers

Each of the Proposed Mergers is subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all. Failure to complete either of the Proposed Mergers could have material adverse effects on us.

On January 13, 2021, we signed the Hygo Merger Agreement and the GMLP Merger Agreement. We currently expect to close the Proposed Mergers in the first half of 2021, subject to customary closing conditions. Each of the Proposed Mergers is not conditioned on the other.

The completion of each of the Proposed Mergers is subject to a number of conditions, including (i) the receipt of all required regulatory approvals and third-party consents; (ii) the receipt of certain specified material third-party consents; (iii) the absence of any legal restraint issued by any court or governmental entity of competent jurisdiction preventing consummation of the transaction; (iv) the accuracy of each party’s representations and warranties, and (v) in the case of the Hygo Merger, the approval for listing on the NASDAQ Global Select Market (the “Nasdaq”) of the shares of Class A common stock to be issued in the Hygo Merger.

There can be no assurance that the conditions to closing of the Proposed Mergers will be satisfied or waived or that other events will not intervene to delay or result in the failure to close the Proposed Mergers. Under the terms of the Hygo Merger Agreement, the Hygo Merger is required to close no later than July 12, 2021, subject to the satisfaction or waiver of certain closing conditions. Under the terms of the GMLP Merger Agreement, the GMLP Merger is required to close no later than July 13, 2021, subject to the satisfaction or waiver of certain closing conditions. Any delay in closing or a failure to close of either of the Proposed Mergers could have a negative impact on our business and the trading price of our common stock.

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In addition, regulators may impose conditions, terms, obligations or restrictions in connection with their approval of or consent to either of the Proposed Mergers, and such conditions, terms, obligations or restrictions may delay completion of either of the Proposed Mergers, require us to take actions that materially alter our existing business or the proposed combined business, including divestitures or similar transactions, or impose additional material costs on or materially limit the revenues of the combined company following the completion of either of the Proposed Mergers. Regulators may impose such conditions, terms, obligations or restrictions, and, if imposed, such conditions, terms, obligations or restrictions may delay or lead to the abandonment of either of the Proposed Mergers.

By purchasing our Class A common stock you are investing in us on a stand-alone basis and recognize that we may not consummate either or both of the Proposed Mergers or realize the expected benefits therefrom if we do. In the event we fail to consummate either or both Proposed Mergers, it is possible that we may have issued a significant number of additional shares of common stock and we will not have acquired the revenue generating assets that will be required to produce the earnings and cash flow we anticipated. If either of the Proposed Mergers is not completed, our ongoing business may be materially adversely affected and, without realizing any of the benefits of having completed either of the Proposed Mergers, we will be subject to a number of risks, including the following:

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the market price of our common stock could decline;

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time and resources committed by our management to matters relating to the applicable Proposed Merger could otherwise have been devoted to pursuing other beneficial opportunities for our Company;

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we may experience negative reactions from the financial markets or from our customers, employees, suppliers and regulators; and

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we will be required to pay the costs relating to each the Proposed Mergers, such as legal, accounting and financial advisory fees, whether or not the Proposed Mergers are completed.

The materialization of any of these risks could adversely impact our ongoing business.

Similarly, delays in the completion of either of the Proposed Mergers could, among other things, result in additional transaction costs, loss of revenue or other negative effects associated with uncertainty about completion of the Proposed Mergers.

We, Hygo and GMLP are each subject to business uncertainties and contractual restrictions while the Proposed Mergers are pending, which could adversely affect the business and operations of the combined Company.

In connection with the pendency of the Proposed Mergers, it is possible that some customers, suppliers and other persons with whom we, Hygo or GMLP have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with us, Hygo or GMLP, as the case may be, as a result of the Proposed Mergers, which could negatively affect our current or the combined Company’s future revenues, earnings and cash flows, regardless of whether the Proposed Mergers are completed.

Under the terms of each of the Merger Agreements, each of Hygo and GMLP is subject to certain restrictions on the conduct of its business prior to completing each of the Proposed Mergers, which may adversely affect its ability to execute certain of its business strategies, including the ability in certain cases to enter into or amend contracts, acquire or dispose of assets, incur indebtedness or fund capital expenditures. Such limitations could adversely affect Hygo’s or GMLP’s business and operations prior to the completion of the applicable Proposed Merger.

Each of the risks described above may be exacerbated by delays or other adverse developments with respect to the completion of either of the Proposed Mergers.

Uncertainties associated with the Proposed Mergers may cause a loss of management personnel and other key employees, and we may have difficulty attracting and motivating management personnel and other key employees, which could adversely affect our future business and operations.

We are dependent on the experience and industry knowledge of our management personnel and other key employees to execute their business plans. Our success after the completion of the Proposed Mergers will depend in part upon our ability to attract, motivate and retain key management personnel and other key employees. Prior to completion of the Proposed Mergers, current and prospective employees may experience uncertainty about their roles within our Company following the completion of the Proposed Mergers, which may have an adverse effect on our ability to attract, motivate or retain management personnel and other key employees. In addition, no assurance can be given that we will be able to attract, motivate or retain management personnel and other key employees to the same extent after the completion of the Proposed Mergers.

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After the Proposed Mergers, we may be unable to successfully integrate the businesses and realize the anticipated benefits of the Proposed Mergers.

The success of the Proposed Mergers will depend, in part, on our ability to successfully combine each of Hygo and GMLP, which currently operate as independent companies, with our business and realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from each combination. If we are unable to achieve these objectives within the anticipated time frame, or at all, the anticipated benefits may not be realized fully, or at all, or may take longer to realize than expected and the value of our common stock may be harmed. Additionally, as a result of the Proposed Mergers, rating agencies may take negative actions against our credit ratings, which may increase our financing costs, including in connection with the financing of the Proposed Mergers.

The Proposed Mergers involve the integration of Hygo and GMLP with our existing business, which is a complex, costly and time-consuming process. The integration of each of Hygo and GMLP into our business may result in material challenges, including, without limitation:

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the diversion of management’s attention from ongoing business concerns and performance shortfalls as a result of the devotion of management’s attention to the Proposed Mergers;

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managing a larger Company;

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maintaining employee morale and attracting and motivating and retaining management personnel and other key employees;

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the possibility of faulty assumptions underlying expectations regarding the integration process;

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retaining existing business and operational relationships and attracting new business and operational relationships;

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consolidating corporate and administrative infrastructures and eliminating duplicative operations;

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coordinating geographically separate organizations;

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unanticipated issues in integrating information technology, communications and other systems;

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unanticipated changes in federal or state laws or regulations; and

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unforeseen expenses or delays associated with either of the Proposed Mergers.

Many of these factors will be outside of our control and any one of them could result in delays, increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy, which could materially affect our financial position, results of operations and cash flows.

Unlike new builds, existing vessels typically do not carry warranties as to their condition. If we inspect existing vessels prior to purchase, such an inspection would normally not provide us with as much knowledge of a vessel’s condition as we would possess if it had been built for us and operated only by us during its life. Repairs and maintenance costs for existing vessels are difficult to predict and may be substantially higher than for vessels we have operated since they were built. These costs could decrease our cash flow and reduce our liquidity and could have an adverse effect on our expected plans for growth.

We may not have discovered undisclosed liabilities or other issues of either Hygo or GMLP during our due diligence process.

In the course of the due diligence review of each of Hygo and GMLP that we conducted prior to the execution of each of the Merger Agreements, we may not have discovered, or may have been unable to quantify, undisclosed liabilities or other issues of Hygo or GMLP and their respective subsidiaries. Examples of such undisclosed liabilities or other issues may include, but are not limited to, pending or threatened litigation, regulatory matters, undisclosed counterparty termination rights, or undisclosed letter of credit or guarantee requirements. Any such undisclosed liabilities or other issues could have an adverse effect on our business, results of operations, financial condition and cash flows following the completion of the Proposed Mergers.

We expect to incur a significant amount of additional debt to fund a portion of the purchase price for the GMLP Merger and as a result of the consummation of the Proposed Mergers.

As of December 31, 2020 we had approximately $1,250 million aggregate principal amount of indebtedness outstanding. On an ongoing basis, we engage with lenders and other financial institutions in an effort to improve our liquidity and capital resources. We may incur additional debt to fund our business and strategic initiatives, and expect to incur additional debt to fund a portion of the purchase price for the GMLP Merger. On January 13, 2021, we obtained financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If we incur additional debt and other obligations, the risks associated with our substantial leverage and the ability to service such debt would increase.

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In addition, in connection with both the Hygo Merger and the GMLP Merger, we will be assuming a significant amount of indebtedness, including guarantees and preferred shares. As such, we will be subject to additional restrictive debt covenants that may limit our ability to finance future operations and capital needs and to pursue business opportunities and activities. In addition, if we fail to comply with any of these restrictions, it could have a material adverse effect on us.

Risks Related to Our Business

We have not yet completed contracting, construction and commissioning of all of our Facilities and Liquefaction Facilities. There can be no assurance that our Facilities and Liquefaction Facilities will operate as expected, or at all.

We have not yet entered into binding construction contracts, issued “final notice to proceed” or obtained all necessary environmental, regulatory, construction and zoning permissions for all of our Facilities (as defined herein) and Liquefaction Facilities. There can be no assurance that we will be able to enter into the contracts required for the development of our Facilities and Liquefaction Facilities on commercially favorable terms, if at all, or that we will be able to obtain all of the environmental, regulatory, construction and zoning permissions we need. In particular, we will require agreements with ports proximate to our Liquefaction Facilities capable of handling the transload of LNG directly from our transportation assets to our occupying vessel. If we are unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, we may not be able to construct and operate these assets as expected, or at all. Additionally, the construction of these kinds of facilities is inherently subject to the risks of cost overruns and delays. There can be no assurance that we will not need to make adjustments to our Facilities and Liquefaction Facilities as a result of the required testing or commissioning of each development, which could cause delays and be costly. Furthermore, if we do enter into the necessary contracts and obtain regulatory approvals for the construction and operation of the Liquefaction Facilities, there can be no assurance that such operations will allow us to successfully export LNG to our Facilities, or that we will succeed in our goal of reducing the risk to our operations of future LNG price variations. If we are unable to construct, commission and operate all of our Facilities and Liquefaction Facilities as expected, or, when and if constructed, they do not accomplish our goals, or if we experience delays or cost overruns in construction, our business, operating results, cash flows and liquidity could be materially and adversely affected. Expenses related to our pursuit of contracts and regulatory approvals related to our Facilities and Liquefaction Facilities still under development may be significant and will be incurred by us regardless of whether these assets are ultimately constructed and operational.

We may experience time delays, unforeseen expenses and other complications while developing our projects. These complications can delay the commencement of revenue-generating activities, reduce the amount of revenue we earn and increase our development costs.

Development projects, including our Facilities, Liquefaction Facilities, power plants, and related infrastructure are often developed in multiple stages involving commercial and governmental negotiations, site planning, due diligence, permit requests, environmental impact studies, permit applications and review, marine logistics planning and transportation and end-user delivery logistics. Projects of this type are subject to a number of risks that may lead to delay, increased costs and decreased economic attractiveness. These risks are often increased in foreign jurisdictions, where legal processes, language differences, cultural expectations, currency exchange requirements, political relations with the U.S. government, changes in the political views and structure, government representatives, new regulations, regulatory reviews, employment laws and diligence requirements can make it more difficult, time-consuming and expensive to develop a project.

A primary focus of our business is the development of projects in foreign jurisdictions, including in locations where we have no prior development experience, and we expect to continue expanding into new jurisdictions in the future, including with our expansion by way of the Proposed Mergers.

Our inexperience in these jurisdictions creates a meaningful risk that we may experience delays, unforeseen expenses or other obstacles that will cause the projects we are developing to take longer and be more expensive than our initial estimates.

While we plan our projects carefully and attempt to complete them according to timelines and budgets that we believe are feasible, we have experienced time delays and cost overruns in some projects that we have developed previously and may experience similar issues with future projects given the inherent complexity and unpredictability of developing infrastructure projects. For example, we previously expected to commence operations of our San Juan Facility and the converted Units 5 and 6 of the San Juan Power Plant (as defined herein) in San Juan, Puerto Rico in the third quarter of 2019. However, due in part to the earthquakes that occurred near Puerto Rico in January 2020 and third-party delays, we began supplying natural gas to Units 5 and 6 in the second quarter of 2020. Delays in the development beyond our estimated timelines, or amendments or change orders to the construction contracts we have entered into and will enter into in the future, could increase the cost of completion beyond the amounts that we estimate. Increased costs could require us to obtain additional sources of financing to continue development on our estimated development timeline or to fund our operations during such development. Any delay in completion of a Facility could cause a delay in the receipt of revenues estimated therefrom or cause a loss of one or more customers in the event of significant delays. As a result of any one of these factors, any significant development delay, whatever the cause, could have a material adverse effect on our business, operating results, cash flows and liquidity.

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Our ability to implement our business strategy may be materially and adversely affected by many known and unknown factors.

Our business strategy relies upon our future ability to successfully market natural gas to end-users, develop and maintain cost-effective logistics in our supply chain and construct, develop and operate energy-related infrastructure in the U.S., Jamaica, Mexico, Puerto Rico, Ireland, Nicaragua, Brazil and other countries where we do not currently operate. Our strategy assumes that we will be able to expand our operations into other countries, including countries in the Caribbean, enter into long-term GSAs and/or PPAs with end-users, acquire and transport LNG at attractive prices, develop infrastructure, including the Pennsylvania Facility (as defined herein), as well as other future projects, into efficient and profitable operations in a timely and cost-effective way, obtain approvals from all relevant federal, state and local authorities, as needed, for the construction and operation of these projects and other relevant approvals and obtain long-term capital appreciation and liquidity with respect to such investments. We cannot assure you if or when we will enter into contracts for the sale of LNG and/or natural gas, the price at which we will be able to sell such LNG and/or natural gas or our costs for such LNG and/or natural gas. Thus, there can be no assurance that we will achieve our target pricing, costs or margins. Our strategy may also be affected by future governmental laws and regulations. Our strategy also assumes that we will be able to enter into strategic relationships with energy end-users, power utilities, LNG providers, shipping companies, infrastructure developers, financing counterparties and other partners. These assumptions are subject to significant economic, competitive, regulatory and operational uncertainties, contingencies and risks, many of which are beyond our control. Additionally, in furtherance of our business strategy, we may acquire operating businesses or other assets in the future. Any such acquisitions would be subject to significant risks and contingencies, including the risk of integration, and we may not be able to realize the benefits of any such acquisitions.

Additionally, our strategy may evolve over time. Our future ability to execute our business strategy is uncertain, and it can be expected that one or more of our assumptions will prove to be incorrect and that we will face unanticipated events and circumstances that may adversely affect our business. Any one or more of the following factors may have a material adverse effect on our ability to implement our strategy and achieve our targets:

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inability to achieve our target costs for the purchase, liquefaction and export of natural gas and/or LNG and our target pricing for long-term contracts;

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failure to develop cost-effective logistics solutions;

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failure to manage expanding operations in the projected time frame;

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inability to structure innovative and profitable energy-related transactions as part of our sales and trading operations and to optimally price and manage position, performance and counterparty risks;

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inability, or failure, of any customer or contract counterparty to perform their contractual obligations to us (for further discussion of counterparty risk, see “— Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long-term contracts that we have entered into or will enter into in the near future, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason, including nonpayment and nonperformance, or if we fail to enter into such contracts at all.”);

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inability to develop infrastructure, including our Facilities and Liquefaction Facilities, as well as other future projects, in a timely and cost-effective manner;

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inability to attract and retain personnel in a timely and cost-effective manner;

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failure of investments in technology and machinery, such as liquefaction technology or LNG tank truck technology, to perform as expected;

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increases in competition which could increase our costs and undermine our profits;

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inability to source LNG and/or natural gas in sufficient quantities and/or at economically attractive prices;

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failure to anticipate and adapt to new trends in the energy sector in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, after the consummation of the Proposed Mergers, Brazil, and elsewhere;

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increases in operating costs, including the need for capital improvements, insurance premiums, general taxes, real estate taxes and utilities, affecting our profit margins;

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inability to raise significant additional debt and equity capital in the future to implement our strategy as well as to operate and expand our business;

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general economic, political and business conditions in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, Brazil and in the other geographic areas in which we intend to operate;

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the severity and duration of world health events, including the recent COVID-19 pandemic and related economic and political impacts on our or our customers’ or suppliers’ operations and financial status;

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inflation, depreciation of the currencies of the countries in which we operate and fluctuations in interest rates;

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failure to win new bids or contracts on the terms, size and within the time frame we need to execute our business strategy;

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failure to obtain approvals from governmental regulators and relevant local authorities for the construction and operation of potential future projects and other relevant approvals;

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uncertainty regarding the timing, pace and extent of an economic recovery in the United States, the other jurisdictions in which we operate and elsewhere, which in turn will likely affect demand for crude oil and natural gas; or

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existing and future governmental laws and regulations.

If we experience any of these failures, such failure may adversely affect our financial condition, results of operations and ability to execute our business strategy.

When we invest significant capital to develop a project, we are subject to the risk that the project is not successfully developed and that our customers do not fulfill their payment obligations to us following our capital investment in a project.

A key part of our business strategy is to attract new customers by agreeing to finance and develop new facilities, power plants, liquefaction facilities and related infrastructure in order to win new customer contracts for the supply of natural gas, LNG or power. This strategy requires us to invest capital and time to develop a project in exchange for the ability to sell natural gas, LNG or power and generate fees from customers in the future. When we develop large projects such as facilities, power plants and large liquefaction facilities, our required capital expenditure may be significant, and we typically do not generate meaningful fees from customers until the project has commenced commercial operations, which may take a year or more to achieve. If the project is not successfully developed for any reason, we face the risk of not recovering some or all of our invested capital, which may be significant. If the project is successfully developed, we face the risks that our customers may not fulfill their payment obligations or may not fulfill other performance obligations that impact our ability to collect payment. Our customer contracts and development agreements do not fully protect us against this risk and, in some instances, may not provide any meaningful protection from this risk. This risk is heightened in foreign jurisdictions, particularly if our counterparty is a government or government-related entity because any attempt to enforce our contractual or other rights may involve long and costly litigation where the ultimate outcome is uncertain.

If we invest capital in a project where we do not receive the payments we expect, we will have less capital to invest in other projects, our liquidity, results of operations and financial condition could be materially and adversely affected, and we could face the inability to comply with the terms of our existing debt or other agreements, which would exacerbate these adverse effects.

We have a limited operating history, which may not be sufficient to evaluate our business and prospects.

We have a limited operating history and track record. As a result, our prior operating history and historical financial statements may not be a reliable basis for evaluating our business prospects or the value of our Class A common stock. We commenced operations on February 25, 2014, and we had net losses of approximately $78.2 million in 2018, $204.3 million in 2019 and $264.0 million in 2020. Our strategy may not be successful, and if unsuccessful, we may be unable to modify it in a timely and successful manner. We cannot give you any assurance that we will be able to implement our strategy on a timely basis, if at all, or achieve our internal model or that our assumptions will be accurate. Our limited operating history also means that we continue to develop and implement various policies and procedures, including those related to project development planning, operational supply chain planning, data privacy and other matters. We will need to continue to build our team to develop and implement our strategies.

We will continue to incur significant capital and operating expenditures while we develop infrastructure for our supply chain, including for the completion of our Facilities and Liquefaction Facilities under construction, as well as other future projects. We will need to invest significant amounts of additional capital to implement our strategy. We have not yet completed constructing all of our Facilities and Liquefaction Facilities and our strategy includes the construction of additional facilities. Any delays beyond the expected development period for these assets would prolong, and could increase the level of, operating losses and negative operating cash flows. Our future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under our customer contracts in relation to the incurrence of project and operating expenses. Our ability to generate any positive operating cash flow and achieve profitability in the future is dependent on, among other things, our ability to develop an efficient supply chain (which may be impacted by the COVID-19 pandemic) and successfully and timely complete necessary infrastructure, including our Facilities and Liquefaction Facilities under construction, and fulfill our gas delivery obligations under our customer contracts.

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Our business is dependent upon obtaining substantial additional funding from various sources, which may not be available or may only be available on unfavorable terms.

We believe we will have sufficient liquidity, cash flow from operations and access to additional capital sources to fund our capital expenditures and working capital needs for the next 12 months. In the future, we expect to incur additional indebtedness to assist us in developing our operations and we are considering alternative financing options, including in specific markets, or the opportunistic sale of one of our non-core assets. If we are unable to obtain additional funding, approvals or amendments to our financings outstanding from time to time, or if additional funding is only available on terms that we determine are not acceptable to us, we may be unable to fully execute our business plan and our business, financial condition or results of operations may be materially adversely affected. Additionally, we may need to adjust the timing of our planned capital expenditures and facilities development depending on the requirements of our existing financing and availability of such additional funding. Our ability to raise additional capital will depend on financial, economic and market conditions, which have increased in volatility and at times have been negatively impacted due to the COVID-19 pandemic, our progress in executing our business strategy and other factors, many of which are beyond our control. We cannot assure you that such additional funding will be available on acceptable terms, or at all. Additional debt financing, if available, may subject us to restrictive covenants that could limit our flexibility in conducting future business activities and could result in us expending significant resources to service our obligations. If we are unable to comply with our existing covenants or any additional covenants and service our debt, we may lose control of our business and be forced to reduce or delay planned investments or capital expenditures, sell assets, restructure our operations or submit to foreclosure proceedings, all of which could result in a material adverse effect upon our business.

A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets, risks relating to the credit risk of our customers and the jurisdictions in which we operate, as well as general risks applicable to the energy sector. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also historically have relied and in the future will likely rely on borrowings under term loans and other debt instruments to fund our capital expenditures. If any of the lenders in the syndicates backing these debt instruments were unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

We may not be profitable for an indeterminate period of time.

We have a limited operating history and did not commence revenue-generating activities until 2016, and did not achieve profitability as of December 31, 2020. We have made and will continue to make significant initial investments to complete construction and begin operations of each of our Facilities, power plants and Liquefaction Facilities, and we will need to make significant additional investments to develop, improve and operate them, as well as all related infrastructure. We also expect to make significant expenditures and investments in identifying, acquiring and/or developing other future projects, including in connection with the Proposed Mergers. We also expect to incur significant expenses in connection with the launch and growth of our business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel. We will need to raise significant additional debt capital to achieve our goals.

We may not be able to achieve profitability, and if we do, we cannot assure you that we would be able to sustain such profitability in the future. Our failure to achieve or sustain profitability would have a material adverse effect on our business.

Our business is heavily dependent upon our international operations, particularly in Jamaica and Puerto Rico, and any disruption to those operations would adversely affect us.

Our operations in Jamaica began in October 2016, when our Montego Bay Facility commenced commercial operations, and continue to grow, and our San Juan Facility became fully operational in the third quarter of 2020. Jamaica and Puerto Rico are subject to acts of terrorism or sabotage and natural disasters, in particular hurricanes, extreme weather conditions, crime and similar other risks which may negatively impact our operations in the region. We may also be affected by trade restrictions, such as tariffs or other trade controls. Additionally, tourism is a significant driver of economic activity in the Caribbean. As a result, tourism directly and indirectly affects local demand for our LNG and therefore our results of operations. Trends in tourism in the Caribbean are primarily driven by the economic condition of the tourists’ home country or territory, the condition of their destination, and the availability, affordability and desirability of air travel and cruises. Additionally, unexpected factors could reduce tourism at any time, including local or global economic recessions, terrorism, travel restrictions, pandemics, severe weather or natural disasters. If we are unable to continue to leverage on the skills and experience of our international workforce and members of management with experience in the jurisdictions in which we operate to manage such risks, we may be unable to provide LNG at an attractive price and our business could be materially affected.

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Because we are currently dependent upon a limited number of customers, the loss of a significant customer could adversely affect our operating results.

A limited number of customers currently represent a substantial majority of our income. Our operating results are currently contingent on our ability to maintain LNG, natural gas, steam and power sales to these customers. At least in the short term, we expect that a substantial majority of our sales will continue to arise from a concentrated number of customers, such as power utilities, railroad companies and industrial end-users. We expect the substantial majority of our revenue for the near future to be from customers in the Caribbean, and assuming the consummation of the Proposed Merger, the Sergipe Terminal and the Sergipe Power Plant and as a result, are subject to any risks specific to those customers and the jurisdictions and markets in which they operate. We may be unable to accomplish our business plan to diversify and expand our customer base by attracting a broad array of customers, which could negatively affect our business, results of operations and financial condition.

Assuming the consummation of the GMLP Merger and following such merger, if we lose any of our charterers and are unable to re-deploy the related vessel for an extended period of time, we will not receive any revenues from that vessel, but we will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt. In addition, under the sale and leaseback arrangement in respect of the Golar Eskimo, if the time charter pursuant to which the Golar Eskimo is operating is terminated, the owner of the Golar Eskimo (which is a wholly-owned subsidiary of China Merchants Bank Leasing) will have the right to require us to purchase the vessel from it unless we are able to place such vessel under a suitable replacement charter within 24 months of the termination. We may not have, or be able to obtain, sufficient funds to make these accelerated payments or prepayments or be able to purchase the Golar Eskimo. In such a situation, the loss of a charterer could have a material adverse effect on our business, results of operations and financial condition.

Our current ability to generate cash is substantially dependent upon the entry into and performance by customers under long-term contracts that we have entered into or will enter into in the near future, and we could be materially and adversely affected if any customer fails to perform its contractual obligations for any reason, including nonpayment and nonperformance, or if we fail to enter into such contracts at all.

Our current results of operations and liquidity are, and will continue to be in the near future, substantially dependent upon performance by JPS (as defined herein), SJPC (as defined herein) and PREPA (as defined herein), which have each entered into long-term GSAs and, in the case of JPS, a PPA in relation to the power produced at the CHP Plant (as defined herein), with us, and Jamalco (as defined herein), which has entered into a long-term SSA with us. While certain of our long-term contracts contain minimum volume commitments, our expected sales to customers under existing contracts are substantially in excess of such minimum volume commitments. Our near-term ability to generate cash is dependent on these customers’ continued willingness and ability to continue purchasing our products and services and to perform their obligations under their respective contracts. Their obligations may include certain nomination or operational responsibilities, construction or maintenance of their own facilities which are necessary to enable us to deliver and sell natural gas or LNG, and compliance with certain contractual representations and warranties.

Our credit procedures and policies may be inadequate to sufficiently eliminate risks of nonpayment and nonperformance. In assessing customer credit risk, we use various procedures including background checks which we perform on our potential customers before we enter into a long-term contract with them. As part of the background check, we assess a potential customer’s credit profile and financial position, which can include their operating results, liquidity and outstanding debt, and certain macroeconomic factors regarding the region(s) in which they operate. These procedures help us to appropriately assess customer credit risk on a case-by-case basis, but these procedures may not be effective in assessing credit risk in all instances. As part of our business strategy, we intend to target customers who have not been traditional purchasers of natural gas, including customers in developing countries, and these customers may have greater credit risk than typical natural gas purchasers. Therefore, we may be exposed to greater customer credit risk than other companies in the industry. Additionally, we may face difficulties in enforcing our contractual rights against contractual counterparties that have not submitted to the jurisdiction of U.S. courts. Further, adverse economic conditions in our industry increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings. The COVID -19 pandemic could adversely impact our customers through decreased demand for power due to decreased economic activity and tourism, or through the adverse economic impact of the pandemic on their power customers. The impact of the COVID-19 pandemic, including governmental and other third-party responses thereto, on our customers could enhance the risk of nonpayment by such customers under our contracts, which would negatively affect our business, results of operations and financial condition.

In particular, JPS and SJPC, which are public utility companies in Jamaica, could be subject to austerity measures imposed on Jamaica by the International Monetary Fund (the “IMF”) and other international lending organizations. Jamaica is currently subject to certain public spending limitations imposed by agreements with the IMF, and any changes under these agreements could limit JPS’s and SJPC’s ability to make payments under their long-term GSAs and, in the case of JPS, its ability to make payments under its PPA, with us. In addition, our ability to operate the CHP Plant is dependent on our ability to enforce the related lease. General Alumina Jamaica Limited (“GAJ”), one of the lessors, is a subsidiary of Noble Group, which completed a financial restructuring in 2018. If GAJ is involved in a bankruptcy or similar proceeding, such proceeding could negatively impact our ability to enforce the lease. If we are unable to enforce the lease due to the bankruptcy of GAJ or for any other reason, we could be unable to operate the CHP Plant or to execute on our contracts related thereto, which could negatively affect our business, results of operations and financial condition. In addition, PREPA is currently subject to bankruptcy proceedings pending in the U.S. District Court for the District of Puerto Rico. As a result, PREPA’s ability to meet its payment obligations under its contracts will be largely dependent upon funding from the Federal Emergency Management Agency or other sources. PREPA’s contracting practices in connection with restoration and repair of PREPA’s electrical grid in Puerto Rico, and the terms of certain of those contracts, have been subject to comment and are the subject of review and hearings by U.S. federal and Puerto Rican governmental entities. In the event that PREPA does not have or does not obtain the funds necessary to satisfy obligations to us under our agreement with PREPA or terminates our agreement prior to the end of the agreed term, our financial condition, results of operations and cash flows could be materially and adversely affected.

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If any of these customers fails to perform its obligations under its contract for the reasons listed above or for any other reason, our ability to provide products or services and our ability to collect payment could be negatively impacted, which could materially adversely affect our operating results, cash flow and liquidity, even if we were ultimately successful in seeking damages from such customer for a breach of contract.

Our contracts with our customers are subject to termination under certain circumstances.

Our contracts with our customers contain various termination rights. For example, each of our long-term customer contracts, including the contracts with JPS, SJPC, Jamalco and PREPA, contain various termination rights allowing our customers to terminate the contract, including, without limitation:

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upon the occurrence of certain events of force majeure;

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if we fail to make available specified scheduled cargo quantities;

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the occurrence of certain uncured payment defaults;

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the occurrence of an insolvency event;

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the occurrence of certain uncured, material breaches; and

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if we fail to commence commercial operations or achieve financial close within the agreed timeframes.

We may not be able to replace these contracts on desirable terms, or at all, if they are terminated. Contracts that we enter into in the future may contain similar provisions. If any of our current or future contracts are terminated, such termination could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

Our business and the development of energy-related infrastructure and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have at various times been and may become volatile due to one or more of the following factors:

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additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG or natural gas from our business;

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imposition of tariffs by China or any other jurisdiction on imports of LNG from the United States;

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insufficient or oversupply of natural gas liquefaction or export capacity worldwide;

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insufficient LNG tanker capacity;

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weather conditions and natural disasters;

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reduced demand and lower prices for natural gas;

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increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

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decreased oil and natural gas exploration activities, including shut-ins and possible proration, which have begun and may continue to decrease the production of natural gas;

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cost improvements that allow competitors to offer LNG regasification services at reduced prices;

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changes in supplies of, and prices for, alternative energy sources, such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;

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changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;

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political conditions in natural gas producing regions;

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adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and

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cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

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Adverse trends or developments affecting any of these factors, including the timing of the impact of these factors in relation to our purchases and sales of natural gas and LNG—in particular prior to our Pennsylvania Facility becoming operational—could result in increases in the prices we have to pay for natural gas or LNG, which could materially and adversely affect the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flows, liquidity and prospects. The COVID-19 pandemic and certain actions by the Organization of the Petroleum Exporting Countries (“OPEC”) related to the supply of oil in the market have caused volatility and disruption in the price of oil which may negatively impact our potential customers’ willingness or ability to enter into new contracts for the purchase of natural gas. Additionally, in situations where our supply chain has capacity constraints and as a result we are unable to receive all volumes under our long-term LNG supply agreements, our supplier may sell volumes of LNG in a mitigation sale to third parties. In these cases, the factors above may impact the price and amount we receive under mitigation sales and we may incur losses that would have an adverse impact on our financial condition, results of operations and cash flows. For example, among other reasons and because spot market LNG prices in the second quarter of 2020 were significantly lower than the price at which we had previously contracted to purchase LNG, we terminated our contractual obligation to purchase LNG for the remainder of 2020 in order to purchase LNG at lower prices on the spot market during that period in exchange for a one-time payment of $105 million. There can be no assurance we will achieve our target cost or pricing goals. In particular, because we have not currently procured fixed-price, long-term LNG supply to meet all future customer demand, increases in LNG prices and/or shortages of LNG supply could adversely affect our profitability. Additionally, we intend to rely on long-term, largely fixed-price contracts for the feedgas that we need in order to manufacture and sell our LNG. Our actual costs and any profit realized on the sale of our LNG may vary from the estimated amounts on which our contracts for feedgas were originally based. There is inherent risk in the estimation process, including significant changes in the demand for and price of LNG as a result of the factors listed above, many of which are outside of our control.

Failure to maintain sufficient working capital could limit our growth and harm our business, financial condition and results of operations.

We have significant working capital requirements, primarily driven by the delay between the purchase of and payment for natural gas and the extended payment terms that we offer our customers. Differences between the date when we pay our suppliers and the date when we receive payments from our customers may adversely affect our liquidity and our cash flows. We expect our working capital needs to increase as our total business increases. If we do not have sufficient working capital, we may not be able to pursue our growth strategy, respond to competitive pressures or fund key strategic initiatives, such as the development of our facilities, which may harm our business, financial condition and results of operations.

Operation of our LNG infrastructure and other facilities that we may construct involves significant risks.

Our existing Facilities and Liquefaction Facilities and expected future facilities face operational risks, including, but not limited to, the following: performing below expected levels of efficiency, breakdowns or failures of equipment, operational errors by trucks, including trucking accidents while transporting natural gas, tankers or tug operators, operational errors by us or any contracted facility operator, labor disputes and weather-related or natural disaster interruptions of operations.

Any of these risks could disrupt our operations and increase our costs, which would adversely affect our business, operating results, cash flows and liquidity.

The operation of the CHP Plant and other power plants will involve particular, significant risks.

The operation of the CHP Plant and other power plants that we operate in the future will involve particular, significant risks, including, among others: failure to maintain the required power generation license(s) or other permits required to operate the power plants; pollution or environmental contamination affecting operation of the power plants; the inability, or failure, of any counterparty to any plant-related agreements to perform their contractual obligations to us including, but not limited to, the lessor’s obligations to us under the CHP Plant lease; decreased demand for power produced, including as a result of the COVID-19 pandemic; and planned and unplanned power outages due to maintenance, expansion and refurbishment. We cannot assure you that future occurrences of any of the events listed above or any other events of a similar or dissimilar nature would not significantly decrease or eliminate the revenues from, or significantly increase the costs of operating, the CHP Plant or other power plants. If the CHP Plant or other power plants are unable to generate or deliver power or steam, as applicable, to our customers, such customers may not be required to make payments under their respective agreements so long as the event continues. Certain customers may have the right to terminate those agreements for certain failures to generate or deliver power or steam, as applicable, and we may not be able to enter into a replacement agreement on terms as favorable as the terminated agreement. In addition, such termination may give rise to termination or other rights under related agreements including related leases. As a consequence, there may be reduced or no revenues from one or more of our power plants, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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Global climate change may in the future increase the frequency and severity of weather events and the losses resulting therefrom, which could have a material adverse effect on the economies in the markets in which we operate or plan to operate in the future and therefore on our business.

Over the past several years, changing weather patterns and climatic conditions, such as global warming, have added to the unpredictability and frequency of natural disasters in certain parts of the world, including the markets in which we operate and intend to operate, and have created additional uncertainty as to future trends. There is a growing consensus today that climate change increases the frequency and severity of extreme weather events and, in recent years, the frequency of major weather events appears to have increased. We cannot predict whether or to what extent damage that may be caused by natural events, such as severe tropical storms and hurricanes, will affect our operations or the economies in our current or future market areas, but the increased frequency and severity of such weather events could increase the negative impacts to economic conditions in these regions and result in a decline in the value or the destruction of our liquefiers and downstream facilities or affect our ability to transmit LNG. In particular, if one of the regions in which our Facilities are operating or under development is impacted by such a natural catastrophe in the future, it could have a material adverse effect on our business. Further, the economies of such impacted areas may require significant time to recover and there is no assurance that a full recovery will occur. Even the threat of a severe weather event could impact our business, financial condition or the price of our Class A common stock.

Hurricanes or other natural or manmade disasters could result in an interruption of our operations, a delay in the completion of our infrastructure projects, higher construction costs or the deferral of the dates on which payments are due under our customer contracts, all of which could adversely affect us.

Storms and related storm activity and collateral effects, or other disasters such as explosions, fires, seismic events, floods or accidents, could result in damage to, or interruption of operations in our supply chain, including at our Facilities, Liquefaction Facilities, or related infrastructure, as well as delays or cost increases in the construction and the development of our proposed facilities or other infrastructure. Changes in the global climate may have significant physical effects, such as increased frequency and severity of storms, floods and rising sea levels; if any such effects were to occur, they could have an adverse effect on our marine and coastal operations. Due to the concentration of our current and anticipated operations in Southern Florida and the Caribbean, we are particularly exposed to the risks posed by hurricanes, tropical storms and their collateral effects. For example, the 2017 Atlantic hurricane season caused extensive and costly damage across Florida and the Caribbean, including Puerto Rico. In addition, earthquakes which occurred near Puerto Rico in January 2020 resulted in a temporary delay of development of our Puerto Rico projects. We are unable to predict with certainty the impact of future storms on our customers, our infrastructure or our operations.

If one or more tankers, pipelines, Facilities, Liquefaction Facilities, equipment or electronic systems that we own, lease or operate or that deliver products to us or that supply our Facilities, Liquefaction Facilities, and customers’ facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist or cyber-attack or event, our operations and construction projects could be delayed and our operations could be significantly interrupted. These delays and interruptions could involve significant damage to people, property or the environment, and repairs could take a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations or that causes us to make significant expenditures not covered by insurance could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Information technology failures and cyberattacks could affect us significantly.

We rely on electronic systems and networks to communicate, control and manage our operations and prepare our financial management and reporting information. If we record inaccurate data or experience infrastructure outages, our ability to communicate and control and manage our business could be adversely affected.

We face various security threats, including cybersecurity threats from third parties and unauthorized users to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our Facilities, Liquefaction Facilities, and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, Facilities, Liquefaction Facilities, and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations. If we were to experience an attack and our security measures failed, the potential consequences to our business and the communities in which we operate could be significant and could harm our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

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Our insurance may be insufficient to cover losses that may occur to our property or result from our operations.

Our current operations and future projects are subject to the inherent risks associated with LNG, natural gas and power operations, including explosions, pollution, release of toxic substances, fires, seismic events, hurricanes and other adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or result in damage to or destruction of the our Facilities, Liquefaction Facilities and assets or damage to persons and property. In addition, such operations and the vessels of third parties on which our current operations and future projects may be dependent face possible risks associated with acts of aggression or terrorism. Some of the regions in which we operate are affected by hurricanes or tropical storms. We do not, nor do we intend to, maintain insurance against all of these risks and losses. In particular, we do not carry business interruption insurance for hurricanes and other natural disasters. Therefore, the occurrence of one or more significant events not fully insured or indemnified against could create significant liabilities and losses which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may be unable to procure adequate insurance coverage at commercially reasonable rates in the future. For example, environmental regulations have led in the past to increased costs for, and in the future may result in the lack of availability of, insurance against risks of environmental damage or pollution. A catastrophic release of natural gas, marine disaster or natural disasters could result in losses that exceed our insurance coverage, which could harm our business, financial condition and operating results. Any uninsured or underinsured loss could harm our business and financial condition. In addition, our insurance may be voidable by the insurers as a result of certain of our actions.

We intend to operate in jurisdictions that have experienced and may in the future experience significant political volatility. Our projects and developments could be negatively impacted by political disruption including risks of delays to our development timelines and delays related to regime change in the jurisdictions in which we intend to operate. We do not carry political risk insurance today. If we choose to carry political risk insurance in the future, it may not be adequate to protect us from loss, which may include losses as a result of project delays or losses as a result of business interruption related to a political disruption. Any attempt to recover from loss from political disruption may be time-consuming and expensive, and the outcome may be uncertain.

Changes in the insurance markets attributable to terrorist attacks or political change may also make certain types of insurance more difficult for us to obtain. In addition, the insurance that may be available may be significantly more expensive than our existing coverage.

We are unable to predict the extent to which the global COVID-19 pandemic will negatively affect our operations, financial performance, nor our ability to achieve our strategic objectives. We are also unable to predict how this global pandemic may affect our customers and suppliers.

The COVID-19 pandemic has caused, and is expected to continue to cause, economic disruptions in various regions, disruptions in global supply chains, significant volatility and disruption of financial markets and in the price of oil. In addition, the pandemic has made travel and commercial activity significantly more cumbersome and less efficient compared to pre-pandemic conditions. Because the severity, magnitude and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly changing and difficult to predict, the pandemic’s impact on our operations and financial performance, as well as its impact on our ability to successfully execute our business strategies and initiatives, remains uncertain and difficult to predict. Further, the ultimate impact of the COVID-19 pandemic on our operations and financial performance depends on many factors that are not within our control, including, but not limited, to: governmental, business and individuals’ actions that have been and continue to be taken in response to the pandemic (including restrictions on travel and transport and workforce pressures); the impact of the pandemic and actions taken in response on global and regional economies, travel, and economic activity; the availability of federal, state, local or non-U.S. funding programs; general economic uncertainty in key global markets and financial market volatility; global economic conditions and levels of economic growth; and the pace of recovery when the COVID-19 pandemic subsides.

The COVID-19 pandemic has subjected our operations, financial performance and financial condition to a number of operational financial risks. The COVID-19 pandemic has also affected Hygo and GMLP. For example, there is an increased risk that final investment decision of Hygo’s Barcarena Terminal (as defined herein) and Santa Catarina Terminal (as defined herein) may be delayed due to severe restrictions on travel within Brazil. Although the services we provide are generally deemed essential, we may face negative impacts from increased operational challenges based on the need to protect employee health and safety, workplace disruptions and restrictions on the movement of people including our employees and subcontractors, and disruptions to supply chains related to raw materials and goods both at our own Facilities, Liquefaction Facilities and at customers and suppliers. We may also experience a lower demand for natural gas at our existing customers and a decrease in interest from potential customers as a result of the pandemic’s impact on the price of available fuel options, including oil-based fuels as well as strains the pandemic places on the capacity of potential customers to evaluate purchasing our goods and services. We may experience customer requests for potential payment deferrals or other contract modifications and delays of potential or ongoing construction projects due to government guidance or customer requests. Conditions in the financial and credit markets may limit the availability of funding and pose heightened risks to future financings we may require. These and other factors we cannot anticipate could adversely affect our business, financial position and results of operations. It is possible that the longer this period of economic and global supply chain and disruption continues, the greater the uncertainty will be regarding the possible adverse impact on our business operations, financial performance and results of operations.

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From time to time, we may be involved in legal proceedings and may experience unfavorable outcomes.

In the future we may be subject to material legal proceedings in the course of our business, including, but not limited to, actions relating to contract disputes, business practices, intellectual property and other commercial tax and regulatory matters. Such legal proceedings may involve claims for substantial amounts of money or for other relief or might necessitate changes to our business or operations, and the defense of such actions may be both time-consuming and expensive. Further, if any such proceedings were to result in an unfavorable outcome, it could have an adverse effect on our business, financial position and results of operations.

Our success depends on key members of our management, the loss of any of whom could disrupt our business operations.

We depend to a large extent on the services of our chief executive officer, Wesley R. Edens, and some of our other executive officers. Mr. Edens does not have an employment agreement with us. The loss of the services of Mr. Edens or one or more of our other key executives could disrupt our operations and increase our exposure to the other risks described in this “Risks Factors” section. We do not maintain key man insurance on Mr. Edens or any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

Our construction of energy-related infrastructure is subject to operational, regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

The construction of energy-related infrastructure, including our Facilities and Liquefaction Facilities, assuming the consummation of the Hygo Merger, the Barcarena Terminal, the Santa Catarina Terminal and other assets in Brazil, as well as other future projects, involves numerous operational, regulatory, environmental, political, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital during construction and thereafter. These potential risks include, among other things, the following:

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we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents or weather conditions;

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we may issue change orders under existing or future engineering, procurement and construction (“EPC”) contracts resulting from the occurrence of certain specified events that may give our customers the right to cause us to enter into change orders or resulting from changes with which we otherwise agree;

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we will not receive any material increase in operating cash flows until a project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

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we may construct facilities to capture anticipated future energy consumption growth in a region in which such growth does not materialize;

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the completion or success of our construction projects may depend on the completion of a third-party construction project (e.g., additional public utility infrastructure projects) that we do not control and that may be subject to numerous additional potential risks, delays and complexities;

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the purchase of the project company holding the rights to develop and operate the Ireland Facility (as defined herein) is subject to a number of contingencies, many of which are beyond our control and could cause us not to acquire the remaining interests of the project company or cause a delay in the construction of our Ireland Facility;

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we may not be able to obtain key permits or land use approvals including those required under environmental laws on terms that are satisfactory for our operations and on a timeline that meets our commercial obligations, and there may be delays, perhaps substantial in length, such as in the event of challenges by citizens groups or non-governmental organizations, including those opposed to fossil fuel energy sources;

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we may be (and have been in select circumstances) subject to local opposition, including the efforts by environmental groups, which may attract negative publicity or have an adverse impact on our reputation; and

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we may be unable to obtain rights-of-way to construct additional energy-related infrastructure or the cost to do so may be uneconomical.

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from future projects, which could have a material adverse effect on our business, financial condition and results of operations.

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We expect to be dependent on our primary building contractor and other contractors for the successful completion of our energy-related infrastructure.

Timely and cost-effective completion of our energy-related infrastructure, including our Facilities and Liquefaction Facilities, and, assuming the consummation of the Hygo Merger, the Sergipe Terminal, the Barcarena Terminal and the Santa Catarina Terminal, as well as future projects, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our primary building contractor and our other contractors under our agreements with them. The ability of our primary building contractor and our other contractors to perform successfully under their agreements with us is dependent on a number of factors, including their ability to:

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design and engineer each of our facilities to operate in accordance with specifications;

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engage and retain third-party subcontractors and procure equipment and supplies;

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respond to difficulties such as equipment failure, delivery delays, schedule changes and failures to perform by subcontractors, some of which are beyond their control;

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attract, develop and retain skilled personnel, including engineers;

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post required construction bonds and comply with the terms thereof;

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manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

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maintain their own financial condition, including adequate working capital.

Until and unless we have entered into an EPC contract for a particular project, in which the EPC contractor agrees to meet our planned schedule and projected total costs for a project, we are subject to potential fluctuations in construction costs and other related project costs. Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the applicable facility, and any liquidated damages that we receive may be delayed or insufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of our primary building contractor and our other contractors to pay liquidated damages under their agreements with us are subject to caps on liability, as set forth therein. Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the applicable facility or result in a contractor’s unwillingness to perform further work. We may hire contractors to perform work in jurisdictions where they do not have previous experience, or contractors we have not previously hired to perform work in jurisdictions we are beginning to develop, which may lead to such contractors being unable to perform according to its respective agreement. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement for any reason, we would be required to engage a substitute contractor, which could be particularly difficult in certain of the markets in which we plan to operate. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

In addition, if our contractors are unable or unwilling to perform according to their respective agreements with us, our projects may be delayed and we may face contractual consequences in our agreements with our customers, including for development services, the supply of natural gas, LNG or steam and the supply of power. We may be required to pay liquidated damages, face increased expenses or reduced revenue, and may face issues complying with certain covenants in such customer agreements or in our financings. We may not have full protection to seek payment from our contractors to compensate us for such payments and other consequences.

We are relying on third-party engineers to estimate the future rated capacity and performance capabilities of our existing and future facilities, and these estimates may prove to be inaccurate.

We are relying on third parties for the design and engineering services underlying our estimates of the future rated capacity and performance capabilities of our Facilities and Liquefaction Facilities, as well as other future projects. If any of these facilities, when actually constructed, fails to have the rated capacity and performance capabilities that we intend, our estimates may not be accurate. Failure of any of our existing Facilities, Liquefaction Facilities or future facilities to achieve our intended future capacity and performance capabilities could prevent us from achieving the commercial start dates under our customer contracts and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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We perform development or construction services from time to time, which are subject to a variety of risks unique to these activities.

From time to time, we may agree to provide development or construction services as part of our customer contracts and such services are subject to a variety of risks unique to these activities. If construction costs of a project exceed original estimates, such costs may have to be absorbed by us, thereby making the project less profitable than originally estimated, or possibly not profitable at all. In addition, a construction project may be delayed due to government or regulatory approvals, supply shortages, or other events and circumstances beyond our control, or the time required to complete a construction project may be greater than originally anticipated. For example, the conversion of Unit 5 and 6 in the San Juan Power Plant was delayed in part due to the earthquakes that occurred near Puerto Rico in January 2020 and third-party delays.

We rely on third-party subcontractors and equipment manufacturers to complete many of our projects. To the extent that we cannot engage subcontractors or acquire equipment or materials in the amounts and at the costs originally estimated, our ability to complete a project in a timely fashion or at a profit may be impaired. If the amount we are required to pay for these goods and services exceeds the amount we have estimated in bidding for fixed-price contracts, we could experience losses in the performance of these contracts. In addition, if a subcontractor or a manufacturer is unable to deliver its services, equipment or materials according to the negotiated terms for any reason including, but not limited to, the deterioration of its financial condition, we may be required to purchase the services, equipment or materials from another source at a higher price. This may reduce the profit we expect to realize or result in a loss on a project for which the services, equipment or materials were needed.

If any such excess costs or project delays were to be material, such events may adversely affect our cash flow and liquidity.

We may not be able to purchase or receive physical delivery of natural gas in sufficient quantities and/or at economically attractive prices to satisfy our delivery obligations under the GSAs, PPA and SSA, which could have a material adverse effect on us.

Under the GSAs with JPS, SJPC and PREPA, we are required to deliver to JPS, SJPC and PREPA specified amounts of natural gas at specified times, while under the SSA with Jamalco, we are required to deliver steam, and under the PPA with JPS, we are required to deliver power, each of which also requires us to obtain sufficient amounts of LNG. However, we may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may provide JPS or SJPC or PREPA or Jamalco with the right to terminate its GSA, PPA or SSA, as applicable. In addition, price fluctuations in natural gas and LNG may make it expensive or uneconomical for us to acquire adequate supply of these items or to sell our inventory of natural gas or LNG at attractive prices.

We are dependent upon third-party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from our tankers and energy-related infrastructure. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, our ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing our revenues. Additionally, under tanker charters, we will be obligated to make payments for our chartered tankers regardless of use. We may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity we have purchased. If any third parties were to default on their obligations under our contracts or seek bankruptcy protection, we may not be able to replace such contracts or purchase or receive a sufficient quantity of natural gas in order to satisfy our delivery obligations under our GSAs, PPA and SSA with LNG produced at our own Liquefaction Facilities. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported on or to our tankers and facilities could have a material adverse effect on our business, financial condition, operating results, cash flow, liquidity and prospects.

While we have entered into contracts with a third-party to purchase a substantial portion of our currently contracted and expected LNG volumes through 2030, we will need to purchase significant additional LNG volumes to meet our delivery obligations to our downstream customers. Failure to secure contracts for the purchase of a sufficient amount of natural gas could materially and adversely affect our business, operating results, cash flows and liquidity.

Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third-party LNG suppliers and shippers negatively impacts our ability to purchase a sufficient amount of LNG or significantly increases our costs for purchasing LNG, our business, operating results, cash flows and liquidity could be materially and adversely affected. There can be no assurances that we will complete the Pennsylvania Facility or be able to supply our Facilities with LNG produced at our own Liquefaction Facilities. Even if we do complete the Pennsylvania Facility, there can be no assurance that it will operate as we expect or that we will succeed in our goal of reducing the risk to our operations of future LNG price variations.

We face competition based upon the international market price for LNG or natural gas.

Our business is subject to the risk of natural gas and LNG price competition at times when we need to replace any existing customer contract, whether due to natural expiration, default or otherwise, or enter into new customer contracts. Factors relating to competition may prevent us from entering into new or replacement customer contracts on economically comparable terms to existing customer contracts, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for natural gas from our business are diverse and include, among others:

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increases in worldwide LNG production capacity and availability of LNG for market supply;

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increases in demand for natural gas but at levels below those required to maintain current price equilibrium with respect to supply;

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increases in the cost to supply natural gas feedstock to our liquefaction projects;

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increases in the cost to supply LNG feedstock to our Facilities;

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decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, heavy fuel oil and ADO;

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decreases in the price of LNG; and

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displacement of LNG or fossil fuels more broadly by alternate fuels or energy sources or technologies (including but not limited to nuclear, wind, solar, biofuels and batteries) in locations where access to these energy sources is not currently available or prevalent.

In addition, we may not be able to successfully execute on our strategy to supply our existing and future customers with LNG produced primarily at our own Liquefaction Facilities upon completion of the Pennsylvania Facility. See “—We have not yet completed contracting, construction and commissioning of all of our Facilities and Liquefaction Facilities. There can be no assurance that our Facilities and Liquefaction Facilities will operate as expected, or at all.”

As part of our business development, we enter into non-binding agreements, and may not agree final definitive documents on similar terms or at all.

Our business development process includes entering into non-binding letters of intent, non-binding memorandums of understanding, non-binding term sheets and responding to requests for proposals with potential customers. These agreements and any award following a request for proposals are subject to negotiating final definitive documents. The negotiation process may cause us or our potential counterparty to adjust the material terms of the agreement, including the price, term, schedule and any related development obligations. We cannot assure you if or when we will enter into binding definitive agreements for transactions initially described in non-binding agreements, and the terms of our binding agreements may differ materially from the terms of the related non-binding agreements.

As part of our efforts to reduce global carbon emissions, we are making investments in green hydrogen energy technologies. The innovative nature of these projects entails the risk that we may never realize the anticipated benefits we hope to achieve for the planet.

We are making investments to develop green hydrogen energy technologies as part of our long-term goal to become one of the world’s leading providers of carbon-free energy. In October 2020, we announced our intention to partner with Long Ridge Energy Terminal and GE Gas Power to transition a power plant to be capable of burning 100% green hydrogen over the next decade, and our investment in H2Pro, an Israel-based company developing a novel, efficient, and low-cost green hydrogen production technology. We expect to make additional investments in this field in the future. Because these technologies are innovative, we may be making investments in unproven business strategies and technologies with which we have limited or no prior development or operating experience. As an investor in these technologies, it is also possible that we could be exposed to claims and liabilities, expenses, regulatory challenges and other risks.

Technological innovation may impair the economic attractiveness of our projects.

The success of our current operations and future projects will depend in part on our ability to create and maintain a competitive position in the natural gas liquefaction industry. In particular, although we plan to build out our delivery logistics chain in Northern Pennsylvania using proven technologies such as those currently in operation at our Miami Facility, we do not have any exclusive rights to any of these technologies. In addition, such technologies may be rendered obsolete or uneconomical by legal or regulatory requirements, technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others, which could materially and adversely affect our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

Changes in legislation and regulations could have a material adverse impact on our business, results of operations, financial condition, liquidity and prospects.

Our business is subject to numerous governmental laws, rules, regulations and requires permits that impose various restrictions and obligations that may have material effects on our results of operations. In addition, each of the applicable regulatory requirements and limitations is subject to change, either through new regulations enacted on the federal, state or local level, or by new or modified regulations that may be implemented under existing law. The nature and extent of any changes in these laws, rules, regulations and permits may be unpredictable and may have material effects on our business. Future legislation and regulations or changes in existing legislation and regulations, or interpretations thereof, such as those relating to the liquefaction, storage, or regasification of LNG, or its transportation could cause additional expenditures, restrictions and delays in connection with our operations as well as other future projects, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. For example, in March 2021, an amendment to the Mexican Power Industry Law (Ley de la Industria Electrica) was published which would reduce the dispatch priority of privately-owned power plants compared to state-owned power plants in Mexico. The amendment is being challenged as unconstitutional, and a judge recently awarded a temporary injunction halting the implementation of the amendment. However, if the amendment is enforced against us, it could negatively affect our plant's dispatch and our revenue and results of operations. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have an adverse effect on our business, the ability to expand our business, including into new markets, results of operations, financial condition, liquidity and prospects.

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Increasing trucking regulations may increase our costs and negatively impact our results of operations.

We are developing a transportation system specifically dedicated to transporting LNG from our Liquefaction Facilities to a nearby port, from which our LNG can be transported to our operations in the Atlantic Basin and elsewhere. This transportation system may include trucks that we or our affiliates own and operate. Any such operations would be subject to various trucking safety regulations, including those which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”). These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials. To a large degree, intrastate motor carrier operations are subject to state and/or local safety regulations that mirror federal regulations but also regulate the weight and size dimensions of loads.

All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of the company’s operating authority by the FMCSA, which could result in a material adverse effect on our business and consolidated results of operations and financial position.

Any trucking operations would be subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include changes in environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

We may not be able to renew or obtain new or favorable charters or leases, which could adversely affect our business, prospects, financial condition, results of operations and cash flows.

We have obtained long-term leases and corresponding rights-of-way agreements with respect to the land on which the Jamaica Facilities, the pipeline connecting the Montego Bay Facility to the Bogue Power Plant (as defined herein), the Miami Facility, the San Juan Facility and the CHP Plant are situated. However, we do not own the land. As a result, we are subject to the possibility of increased costs to retain necessary land use rights as well as local law. If we were to lose these rights or be required to relocate, our business could be materially and adversely affected. The Miami Facility is currently located on land we are leasing from an affiliate. Any payments under the existing lease or future modifications or extensions to the lease could involve transacting with an affiliate. We have also entered into LNG tanker charters in order to secure shipping capacity for our import of LNG to the Jamaica Facilities.

Our ability to renew existing charters or leases for our current projects or obtain new charters or leases for our future projects will depend on prevailing market conditions upon expiration of the contracts governing the leasing or charter of the applicable assets. Therefore, we may be exposed to increased volatility in terms of rates and contract provisions. Likewise, our counterparties may seek to terminate or renegotiate their charters or leases with us. If we are not able to renew or obtain new charters or leases in direct continuation, or if new charters or leases are entered into at rates substantially above the existing rates or on terms otherwise less favorable compared to existing contractual terms, our business, prospects, financial condition, results of operations and cash flows could be materially adversely affected.

We may not be able to successfully enter into contracts or renew existing contracts to charter tankers in the future, which may result in us not being able to meet our obligations.

We enter into time charters of ocean-going tankers for the transportation of LNG, which extend for varying lengths of time. We may not be able to successfully enter into contracts or renew existing contracts to charter tankers in the future, which may result in us not being able to meet our obligations. We are also exposed to changes in market rates and availability for tankers, which may affect our earnings. Fluctuations in rates result from changes in the supply of and demand for capacity and changes in the demand for seaborne carriage of commodities. Because the factors affecting the supply and demand are outside of our control and are unpredictable, the nature, timing, direction and degree of changes in industry conditions are also unpredictable.

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We rely on the operation of tankers under our time charters and ship-to-ship kits to transfer LNG between ships. The operation of ocean-going tankers and kits carries inherent risks. These risks include the possibility of:

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natural disasters;

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mechanical failures;

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grounding, fire, explosions and collisions;

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piracy;

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human error; and

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war and terrorism.

We do not currently maintain a redundant supply of ships, ship-to-ship kits or other equipment. As a result, if our current equipment fails, is unavailable or insufficient to service our LNG purchases, production, or delivery commitments we may need to procure new equipment, which may not be available or be expensive to obtain. Any such occurrence could delay the start of operations of facilities we intend to commission, interrupt our existing operations and increase our operating costs. Any of these results could have a material adverse effect on our business, financial condition and operating results.

The operation of LNG carriers is inherently risky, and an incident resulting in significant loss or environmental consequences involving an LNG vessel could harm our reputation and business.

Cargoes of LNG and our chartered vessels are at risk of being damaged or lost because of events such as:

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marine disasters;

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piracy;

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bad weather;

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mechanical failures;

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environmental accidents;

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grounding, fire, explosions and collisions;

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human error; and

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war and terrorism.

An accident involving our cargoes or any of our chartered vessels could result in any of the following:

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death or injury to persons, loss of property or environmental damage;

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delays in the delivery of cargo;

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loss of revenues;

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termination of charter contracts;

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governmental fines, penalties or restrictions on conducting business;

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higher insurance rates; and

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damage to our reputation and customer relationships generally.

Any of these circumstances or events could increase our costs or lower our revenues.

If our chartered vessels suffer damage as a result of such an incident, they may need to be repaired. The loss of earnings while these vessels are being repaired would decrease our results of operations. If a vessel we charter were involved in an accident with the potential risk of environmental impacts or contamination, the resulting media coverage could have a material adverse effect on our reputation, our business, our results of operations and cash flows and weaken our financial condition. These risks also affect Hygo and GMLP and would remain relevant following the Proposed Mergers.

Our chartered vessels operating in certain jurisdictions including the United States, now or in the future, will be subject to cabotage laws including the Merchant Marine Act of 1920, as amended (the “Jones Act”).

Certain activities related to our logistics and shipping operations may constitute “coastwise trade” within the meaning of laws and regulations of the U.S. and other jurisdictions. Under these laws and regulations, often referred to as cabotage laws, including the Jones Act, in the U.S., only vessels meeting specific national ownership and registration requirements or which are subject to an exception or exemption, may engage in such “coastwise trade”. When we operate or charter foreign-flagged vessels, we do so within the current interpretation of such cabotage laws with respect to permitted activities for foreign-flagged vessels. Significant changes in cabotage laws or to the interpretation of such laws in the places where we operate could affect our ability to operate or charter, or competitively operate or charter, our foreign-flagged vessels in those waters. If we do not continue to comply with such laws and regulations, we could incur severe penalties, such as fines or forfeiture of any vessels or their cargo, and any noncompliance or allegations of noncompliance could disrupt our operations in the relevant jurisdiction. Any noncompliance or alleged noncompliance could have a material adverse effect on our reputation, our business, our results of operations and cash flows, and could weaken our financial condition. These risks also affect Hygo and GMLP and would remain relevant following the Proposed Mergers.

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Our chartered vessels operating in international waters, now or in the future, will be subject to various international and local laws and regulations relating to protection of the environment.

Our chartered vessels’ operations in international waters and in the territorial waters of other countries are regulated by extensive and changing international, national and local environmental protection laws, regulations, treaties and conventions in force in international waters, the jurisdictional waters of the countries in which our vessels operate, as well as the countries of our vessels’ registration, including those governing oil spills, discharges to air and water, the handling and disposal of hazardous substances and wastes and the management of ballast water. The International Maritime Organization (“IMO”) International Convention for the Prevention of Pollution from Ships of 1973, as amended from time to time, and generally referred to as “MARPOL,” can affect operations of our chartered vessels. In addition, our chartered LNG vessels may become subject to the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea (the “HNS Convention”), adopted in 1996 and subsequently amended by a Protocol to the HNS Convention in April 2010. Other regulations include, but are not limited to, the designation of Emission Control Areas under MARPOL, the IMO International Convention on Civil Liability for Oil Pollution Damage of 1969, as amended from time to time, the International Convention on Civil Liability for Bunker Oil Pollution Damage, the IMO International Convention for the Safety of Life at Sea of 1974, as amended from time to time, the International Safety Management Code for the Safe Operations of Ships and for Pollution Prevention, the IMO International Convention on Load Lines of 1966, as amended from time to time and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004.

Moreover, the overall trends are towards more regulations and more stringent requirements which are likely to add to our costs of doing business. For example, IMO regulations, which became applicable on January 1, 2020, limit the sulfur content of fuel oil for ships to 0.5 weight percent starting January 1, 2020. Likewise, the European Union is considering extending its emissions trading scheme to maritime transport to reduce GHG emissions from vessels. We contract with leading vessel providers in the LNG market and look for them to take the lead in maintaining compliance with all such requirements, although the terms of our charter agreements may call for us to bear some or all of the associated costs. While we believe we are similarly situated with respect to other companies that charter vessels, we cannot assure you that these requirements will not have a material effect on our business.

Our chartered vessels operating in U.S. waters, now or in the future, will also be subject to various federal, state and local laws and regulations relating to protection of the environment, including the OPA, the CERCLA, the CWA and the CAA. In some cases, these laws and regulations require governmental permits and authorizations before conducting certain activities. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Failure to comply with these laws and regulations may result in substantial civil and criminal fines and penalties. As with the industry generally, our chartered vessels’ operations will entail risks in these areas, and compliance with these laws and regulations, which may be subject to frequent revisions and reinterpretation, may increase our overall cost of business.

There may be shortages of LNG tankers worldwide, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We rely on ocean-going LNG tankers and freight carriers (for ISO containers) for the movement of LNG. Consequently, our ability to provide services to our customers could be adversely impacted by shifts in tanker market dynamics, shortages in available cargo capacity, changes in policies and practices such as scheduling, pricing, routes of service and frequency of service, or increases in the cost of fuel, taxes and labor, and other factors not within our control. The construction and delivery of LNG tankers require significant capital and long construction lead times, and the availability of the tankers could be delayed to the detriment of our LNG business and our customers because of:

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an inadequate number of shipyards constructing LNG tankers and a backlog of orders at these shipyards;

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political or economic disturbances in the countries where the tankers are being constructed; changes in governmental regulations or maritime self-regulatory organizations;

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work stoppages or other labor disturbances at the shipyards, including as a result of the COVID-19 pandemic;

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bankruptcy or other financial crisis of shipbuilders;

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quality or engineering problems;

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weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; or

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shortages of or delays in the receipt of necessary construction materials.

Changes in ocean freight capacity, which are outside our control, could negatively impact our ability to provide natural gas if LNG shipping capacity is adversely impacted and LNG transportation costs increase because we may bear the risk of such increases and may not be able to pass these increases on to our customers. Material interruptions in service or stoppages in LNG transportation could adversely impact our business, results of operations and financial condition.

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Competition in the LNG industry is intense, and some of our competitors have greater financial, technological and other resources than we currently possess.

We operate in the highly competitive area of LNG production and face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies and utilities, many of which have been in operation longer than us.

Many competing companies have secured access to, or are pursuing development or acquisition of, LNG facilities in North America. We may face competition from major energy companies and others in pursuing our proposed business strategy to provide liquefaction and export products and services. In addition, competitors have and are developing LNG facilities in other markets, which will compete with our LNG facilities. Some of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources than we currently possess. We also face competition for the contractors needed to build our facilities. The superior resources that some of these competitors have available for deployment could allow them to compete successfully against us, which could have a material adverse effect on our business, ability to realize benefits from future projects, results of operations, financial condition, liquidity and prospects.

Failure of LNG to be a competitive source of energy in the markets in which we operate, and seek to operate, could adversely affect our expansion strategy.

Our operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which we operate. In the United States, due mainly to a historic abundant supply of natural gas and discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the domestic liquefaction component of our business plan is dependent, in part, on the extent to which natural gas can, for significant periods and in significant volumes, be produced in the United States at a lower cost than the cost to produce some domestic supplies of other alternative energy sources, and that it can be transported at reasonable rates through appropriately scaled infrastructure. The COVID-19 pandemic and actions by OPEC have significantly impacted energy markets, and the price of oil has recently traded at historic low prices.

Potential expansion in the Caribbean and other parts of world where we may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. For example, in the Caribbean, due mainly to a lack of regasification infrastructure and an underdeveloped international market for natural gas, natural gas has not yet developed into a significant energy source. The success of our operations in the Caribbean is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to Caribbean customers at a lower cost than the cost to deliver other alternative energy sources.

Political instability in foreign countries that export LNG, or strained relations between such countries and countries in the Caribbean, may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the Caribbean. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to non-Caribbean markets or from or to our competitors’ LNG facilities. Natural gas also competes with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy, which may become available at a lower cost in certain markets.

As a result of these and other factors, natural gas may not be a competitive source of energy in the markets we intend to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect our ability to deliver LNG or natural gas to our customers in the Caribbean or other locations on a commercial basis.

Any use of hedging arrangements may adversely affect our future operating results or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the purchase of natural gas, we may enter into futures, swaps and option contracts traded or cleared on the Intercontinental Exchange and the New York Mercantile Exchange or over-the-counter (“OTC”) options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:

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expected supply is less than the amount hedged;

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the counterparty to the hedging contract defaults on its contractual obligations; or

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there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

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The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change. However, we do not currently have any hedging arrangements, and failure to properly hedge our positions against changes in natural gas prices could also have a material adverse effect on our business, financial condition and operating results.

Our risk management strategies cannot eliminate all LNG price and supply risks. In addition, any non-compliance with our risk management strategies could result in significant financial losses.

Our strategy is to maintain a manageable balance between LNG purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the LNG purchased by selling LNG for physical delivery to third-party users, such as public utilities, shipping/marine cargo companies, industrial users, railroads, trucking fleets and other potential end-users converting from traditional ADO or oil fuel to natural gas. These strategies cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated supply chain could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions. We are also exposed to basis risks when LNG is purchased against one pricing index and sold against a different index. Moreover, we are also exposed to other risks, including price risks on LNG we own, which must be maintained in order to facilitate transportation of the LNG to our customers or to our Facilities. If we were to incur a material loss related to commodity price risks, it could have a material adverse effect on our financial position, results of operations and cash flows. There can be no assurance that we will complete the Pennsylvania Facility or be able to supply our Facilities and the CHP Plant with LNG produced at our own Liquefaction Facilities. Even if we do complete the Pennsylvania Facility, there can be no assurance that it will operate as expected or that we will succeed in our goal of reducing the risk to our operations of future LNG price variations.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us.

We are dependent upon the available labor pool of skilled employees, including truck drivers. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our energy-related infrastructure and to provide our customers with the highest quality service. In addition, the tightening of the transportation related labor market due to the shortage of skilled truck drivers may affect our ability to hire and retain skilled truck drivers and require us to pay increased wages. Our affiliates in the United States who hire personnel on our behalf are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. We are also subject to applicable labor regulations in the other jurisdictions in which we operate, including Jamaica. We may face challenges and costs in hiring, retaining and managing our Jamaican and other employee base. A shortage in the labor pool of skilled workers, particularly in Jamaica or the United States, or other general inflationary pressures or changes in applicable laws and regulations, could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. Any increase in our operating costs could materially and adversely affect our business, financial condition, operating results, liquidity and prospects.

Our current lack of asset and geographic diversification could have an adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The substantial majority of our anticipated revenue in 2021 will be dependent upon our assets and customers in Jamaica and Puerto Rico. Jamaica and Puerto Rico have historically experienced economic volatility and the general condition and performance of their economies, over which we have no control, may affect our business, financial condition and results of operations. Due to our current lack of asset and geographic diversification, an adverse development at the Jamaica Facilities or our San Juan Facility, in the energy industry or in the economic conditions in Jamaica or Puerto Rico, would have a significantly greater impact on our financial condition and operating results than if we maintained more diverse assets and operating areas.

We may incur impairments to long-lived assets.

We test our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, and decline of our market capitalization, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our long-lived assets, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our operating results.

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A major health and safety incident involving LNG or the energy industry more broadly or relating to our business may lead to more stringent regulation of LNG operations or the energy business generally, could result in greater difficulties in obtaining permits, including under environmental laws, on favorable terms, and may otherwise lead to significant liabilities and reputational damage.

Health and safety performance is critical to the success of all areas of our business. Any failure in health and safety performance from our operations may result in an event that causes personal harm or injury to our employees, other persons, and/or the environment, as well as the imposition of injunctive relief and/or penalties for non-compliance with relevant regulatory requirements or litigation. Any such failure that results in a significant health and safety incident may be costly in terms of potential liabilities, and may result in liabilities that exceed the limits of our insurance coverage. Such a failure, or a similar failure elsewhere in the energy industry (including, in particular, LNG liquefaction, storage, transportation or regasification operations), could generate public concern, which may lead to new laws and/or regulations that would impose more stringent requirements on our operations, have a corresponding impact on our ability to obtain permits and approvals, and otherwise jeopardize our reputation or the reputation of our industry as well as our relationships with relevant regulatory agencies and local communities. Individually or collectively, these developments could adversely impact our ability to expand our business, including into new markets. Similarly, such developments could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The swaps regulatory and other provisions of the Dodd-Frank Act and the rules adopted thereunder and other regulations, including EMIR and REMIT, could adversely affect our ability to hedge risks associated with our business and our operating results and cash flows.

Title VII of the Dodd-Frank Act established federal regulation of the OTC derivatives market and made other amendments to the Commodity Exchange Act that are relevant to our business. The provisions of Title VII of the Dodd-Frank Act and the rules adopted thereunder by the Commodity Futures Trading Commission (the “CFTC”), the SEC and other federal regulators may adversely affect our ability to manage certain of our risks on a cost-effective basis. Such laws and regulations may also adversely affect our ability to execute our strategies with respect to hedging our exposure to variability in expected future cash flows attributable to the future sale of our LNG inventory and to price risk attributable to future purchases of natural gas to be utilized as fuel to operate our Facilities, our CHP Plant and to secure natural gas feedstock for our Liquefaction Facilities.

The CFTC has proposed new rules setting limits on the positions in certain core futures contracts, economically equivalent futures contracts, options contracts and swaps for or linked to certain physical commodities, including natural gas, held by market participants, with limited exemptions for certain bona fide hedging and other types of transactions. The CFTC has also adopted final rules regarding aggregation of positions, under which a party that controls the trading of, or owns 10% or more of the equity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for purposes of determining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief, until August 12, 2022, from various conditions and requirements in the final aggregation rules. With the implementation of the final aggregation rules and upon the adoption and effectiveness of final CFTC position limits rules, our ability to execute our hedging strategies described above could be limited. It is uncertain at this time whether, when and in what form the CFTC’s proposed new position limits rules may become final and effective.

Under the Dodd-Frank Act and the rules adopted thereunder, we may be required to clear through a derivatives clearing organization any swaps into which we enter that fall within a class of swaps designated by the CFTC for mandatory clearing and we could have to execute trades in such swaps on certain trading platforms. The CFTC has designated six classes of interest rate swaps and credit default swaps for mandatory clearing, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for any swaps entered into to hedge our commercial risks, if we fail to qualify for that exception and have to clear such swaps through a derivatives clearing organization, we could be required to post margin with respect to such swaps, our cost of entering into and maintaining such swaps could increase and we would not enjoy the same flexibility with the cleared swaps that we enjoy with the uncleared OTC swaps we may enter. Moreover, the application of the mandatory clearing and trade execution requirements to other market participants, such as Swap Dealers, may change the cost and availability of the swaps that we may use for hedging.

As required by the Dodd-Frank Act, the CFTC and the federal banking regulators have adopted rules requiring certain market participants to collect initial and variation margin with respect to uncleared swaps from their counterparties that are financial end-users and certain registered Swap Dealers and Major Swap Participants. The requirements of those rules are subject to a phased-in compliance schedule, which commenced on September 1, 2016. Although we believe we will qualify as a non-financial end user for purposes of these rules, were we not to do so and have to post margin as to our uncleared swaps in the future, our cost of entering into and maintaining swaps would be increased. In June 2011, the Basel Committee on the Banking Supervision, an international trade body comprised of senior representatives of bank supervisory authorities and central banks from 27 countries, including the United States and the European Union, announced the final framework for a comprehensive set of capital and liquidity standards, commonly referred to as “Basel III.” Our counterparties that are subject to the Basel III capital requirements may increase the cost to us of entering into swaps with them or, although not required to collect margin from us under the margin rules, require us to post collateral with them in connection with such swaps in order to offset their increased capital costs or to reduce their capital costs to maintain those swaps on their balance sheets.

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The Dodd-Frank Act also imposes regulatory requirements on swaps market participants, including Swap Dealers and other swaps entities as well as certain regulations on end-users of swaps, including regulations relating to swap documentation, reporting and recordkeeping, and certain business conduct rules applicable to Swap Dealers and other swaps entities. Together with the Basel III capital requirements on certain swaps market participants, these regulations could significantly increase the cost of derivative contracts (including through requirements to post margin or collateral), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against certain risks that we encounter, and reduce our ability to monetize or restructure derivative contracts and to execute our hedging strategies. If, as a result of the swaps regulatory regime discussed above, we were to forgo the use of swaps to hedge our risks, such as commodity price risks that we encounter in our operations, our operating results and cash flows may become more volatile and could be otherwise adversely affected.

The European Market Infrastructure Regulation (“EMIR”) may result in increased costs for OTC derivative counterparties and also lead to an increase in the costs of, and demand for, the liquid collateral that EMIR requires central counterparties to accept. Although we expect to qualify as a non-financial counterparty under EMIR and thus not be required to post margin under EMIR, our subsidiaries and affiliates operating in the Caribbean may still be subject to increased regulatory requirements, including recordkeeping, marking to market, timely confirmations, derivatives reporting, portfolio reconciliation and dispute resolution procedures. Regulation under EMIR could significantly increase the cost of derivatives contracts, materially alter the terms of derivatives contracts and reduce the availability of derivatives to protect against risks that we encounter. The increased trading costs and collateral costs may have an adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our subsidiaries and affiliates operating in the Caribbean may be subject to the Regulation on Wholesale Energy Market Integrity and Transparency (“REMIT”) as wholesale energy market participants. This classification imposes increased regulatory obligations on our subsidiaries and affiliates, including a prohibition to use or disclose insider information or to engage in market manipulation in wholesale energy markets, and an obligation to report certain data. These regulatory obligations may increase the cost of compliance for our business and if we violate these laws and regulations, we could be subject to investigation and penalties.

The design, construction and operation of energy-related infrastructure, including our existing and proposed facilities, the import and export of LNG and the transportation of natural gas, are highly regulated activities at the federal, state and local levels. Approvals of the DOE under Section 3 of the NGA, as well as several other material governmental and regulatory permits, approvals and authorizations, including under the CAA and the CWA and their state analogues, may be required in order to construct and operate an LNG facility and export LNG. Permits, approvals and authorizations obtained from the DOE and other federal and state regulatory agencies also contain ongoing conditions, and additional requirements may be imposed. Certain federal permitting processes may trigger the requirements of the National Environmental Policy Act (“NEPA”), which requires federal agencies to evaluate major agency actions that have the potential to significantly impact the environment. Compliance with NEPA may extend the time and/or increase the costs for obtaining necessary governmental approvals associated with our operations and create independent risk of legal challenges to the adequacy of the NEPA analysis, which could result in delays that may adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and profitability. On July 15, 2020, the White House Council on Environmental Quality issued a final rule revising NEPA regulations; however, the regulations, which would become effective 60 days after publication, have been challenged in court, and thus the impacts of any such revisions are uncertain at this time. On June 18, 2020, we received an order from FERC, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the NGA. Because we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. The matter was raised during a FERC open meeting held on January 19, 2021 but was not resolved, is on the agenda during the FERC open meeting to be held on March 18, 2021, and remains pending. We do not know if or when FERC will respond to our reply, or the outcome of any such response. Although FERC has civil penalty authority and the authority to authorize the siting, construction, and operation of jurisdictional LNG facilities, we do not know, nor has FERC indicated, what remedy FERC may require if FERC determines that our San Juan Facility is subject to FERC’s Section 3 jurisdiction. In addition, we may be subject to additional requirements and new regulations by relevant authorities in Jamaica, Mexico, Ireland, Nicaragua, Brazil or other jurisdictions, including with respect to land use approvals and permits needed to construct and operate our facilities and sell LNG and power.

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We cannot control the outcome of any review and approval process, including whether or when any such permits, approvals and authorizations will be obtained, the terms of their issuance, or possible appeals or other potential interventions by third parties that could interfere with our ability to obtain and maintain such permits, approvals and authorizations or the terms thereof. If we are unable to obtain and maintain such permits, approvals and authorizations on favorable terms, we may not be able to recover our investment in our projects and may be subject to financial penalties under our customer and other agreements. Many of these permits, approvals and authorizations require public notice and comment before they can be issued, which can lead to delays to respond to such comments, and even potentially to revise the permit application. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations on favorable terms, or that we will be able to obtain them on a timely basis, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, financial condition, operating results, liquidity and prospects. Moreover, many of these permits, approvals and authorizations are subject to administrative and judicial challenges, which can delay and protract the process for obtaining and implementing permits and can also add significant costs and uncertainty.

Existing and future environmental, health and safety laws and regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

Our business is now and will in the future be subject to extensive federal, state and local laws and regulations both in the United States and in other jurisdictions where we operate. These requirements regulate and restrict, among other things: the siting and design of our facilities; discharges to air, land and water, with particular respect to the protection of human health, the environment and natural resources and safety from risks associated with storing, receiving and transporting LNG; the handling, storage and disposal of hazardous materials, hazardous waste and petroleum products; and remediation associated with the release of hazardous substances. For example, PHMSA has promulgated detailed regulations governing LNG facilities under its jurisdiction to address siting, design, construction, equipment, operations, maintenance, personnel qualifications and training, fire protection and security. While the Miami Facility is subject to these regulations, none of our LNG facilities currently under development are subject to PHMSA’s jurisdiction, but state and local regulators can impose similar siting, design, construction and operational requirements. In addition, the U.S. Coast Guard regulations require certain security and response plans, protocols and trainings to mitigate and reduce the risk of intentional or accidental impacts to energy transportation and production infrastructure located in certain domestic ports.

Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up any such hazardous substances that may be released into the environment at or from our facilities and for any resulting damage to natural resources.

Many of these laws and regulations, such as the CAA and the CWA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentrations of substances that can be emitted into the environment in connection with the construction and operation of our facilities, and require us to obtain and maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. For example, the Pennsylvania Department of Environmental Protection laws and regulations will apply to the construction and operation of the Pennsylvania Facility. Relevant local authorities may also require us to obtain and maintain permits associated with the construction and operation of our facilities, including with respect to land use approvals. Failure to comply with these laws and regulations could lead to substantial liabilities, fines and penalties or capital expenditures related to pollution control equipment and restrictions or curtailment of our operations, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Other future legislation and regulations could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. In October 2017, the U.S. Government Accountability Office issued a legal determination that a 2013 interagency guidance document was a “rule” subject to the Congressional Review Act (“CRA”). This legal determination could open a broader set of agency guidance documents to potential disapproval and invalidation under the CRA, potentially increasing the likelihood that laws and regulations applicable to our business will become subject to revised interpretations in the future that we cannot predict. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Greenhouse Gases/Climate Change. The threat of climate change continues to attract considerable attention in the United States and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state government levels to monitor and limit existing and future GHG emissions. As a result, our operations are subject to a series of risks associated with the processing, transportation, and use of fossil fuels and emission of GHGs.

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In the United States to date, no comprehensive climate change legislation has been implemented at the federal level, although various individual states and state coalitions have adopted or considered adopting legislation, regulations or other regulatory initiatives, including GHG cap and trade programs, carbon taxes, reporting and tracking programs, and emission restrictions, pollution reduction incentives, or renewable energy or low-carbon replacement fuel quotas. At the international level, the United Nations-sponsored “Paris Agreement” was signed by 197 countries who agreed to limit their GHG emissions through non-binding, individually-determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement, effective February 19, 2021, and other countries where we operate or plan to operate, including Jamaica, Ireland, Mexico, and Nicaragua, have signed or acceded to this agreement. However, the scope of future climate and GHG emissions-focused regulatory requirements, if any, remain uncertain.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political uncertainty in the United States. For example, based in part on the publicized climate plan and pledges by President Biden, there may be significant legislation, rulemaking, or executive orders that seek to address climate change, incentivize low-carbon infrastructure or initiatives, or ban or restrict the exploration and production of fossil fuels. For example, although the U.S. has withdrawn from the Paris Agreement, President Biden has issued executive orders recommitting the U.S. to the Paris Agreement and calling for for the federal government to begin formulating the United States nationally determined emissions reductions goal under the agreement with the U.S. recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the Paris Agreement’s goals.

Climate-related litigation and permitting risks are also increasing, as a number of cities, local governments and private organizations have sought to either bring suit against oil and natural gas companies in state or federal court, alleging various public nuisance claims, or seek to challenge permits required for infrastructure development. Fossil fuel producers are also facing general risks of shifting capital availability due to stockholder concern over climate change and potentially stranded assets in the event of future, comprehensive climate and GHG-related regulation. While several of these cases have been dismissed, there is no guarantee how future lawsuits might be resolved.

The adoption and implementation of new or more comprehensive international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent restrictions on GHG emissions could result in increased compliance costs, and thereby reduce demand for or erode value for, the natural gas that we process and market. Additionally, political, litigation, and financial risks may result in reduced natural gas production activities, increased liability for infrastructure damages as a result of climatic changes, or an impaired ability to continue to operate in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.

The adoption and implementation of any U.S. federal, state or local regulations or foreign regulations imposing obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur significant costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for natural gas and natural gas products. The potential increase in our operating costs could include new costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions program. We may not be able to recover such increased costs through increases in customer prices or rates. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to GHGs, or restrict their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows.

Fossil Fuels. Our business activities depend upon a sufficient and reliable supply of natural gas feedstock, and are therefore subject to concerns in certain sectors of the public about the exploration, production and transportation of natural gas and other fossil fuels and the consumption of fossil fuels more generally. Legislative and regulatory action, and possible litigation, in response to such public concerns may also adversely affect our operations. We may be subject to future laws, regulations, or actions to address such public concern with fossil fuel generation, distribution and combustion, greenhouse gases and the effects of global climate change.

Our customers may also move away from using fossil fuels such as LNG for their power generation needs for reputational or perceived risk-related reasons. These matters represent uncertainties in the operation and management of our business, and could have a material adverse effect on our financial position, results of operations and cash flows.

Hydraulic Fracturing. Certain of our suppliers of natural gas and LNG employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations (including shale formations), which currently entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. Moreover, hydraulically fractured natural gas wells account for a significant percentage of the natural gas production in the U.S.; the U.S. Energy Information Administration reported in 2016 that hydraulically fractured wells provided two-thirds of U.S. marketed gas production in 2015. The requirements for permits or authorizations to conduct these activities vary depending on the location where such drilling and completion activities will be conducted. Several states have adopted or considered adopting regulations to impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations, or to ban hydraulic fracturing altogether. As with most permitting and authorization processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit or approval to be issued and any conditions which may be imposed in connection with the granting of the permit. Certain regulatory authorities have delayed or suspended the issuance of permits or authorizations while the potential environmental impacts associated with issuing such permits can be studied and appropriate mitigation measures evaluated. In addition to state laws, some local municipalities have adopted or considered adopting land use restrictions, such as city ordinances, that may restrict the performance of or prohibit the well drilling in general and/or hydraulic fracturing in particular.

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Hydraulic fracturing activities are typically regulated at the state level, but federal agencies have asserted regulatory authority over certain hydraulic fracturing activities and equipment used in the production, transmission and distribution of oil and natural gas, including such oil and natural gas produced via hydraulic fracturing. Federal and state legislatures and agencies may seek to further regulate or even ban such activities. For example, the Delaware River Basin Commission (“DRBC”), a regional body created via interstate compact responsible for, among other things, water quality protection, water supply allocation, regulatory review, water conservation initiatives, and watershed planning in the Delaware River Basin, has implemented a de facto ban on hydraulic fracturing activities in that basin since 2010 pending the approval of new regulations governing natural gas production activity in the basin. More recently, the DRBC has stated that it will consider new regulations that would ban natural gas production activity, including hydraulic fracturing, in the basin. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, natural gas prices in North America could rise, which in turn could materially adversely affect the relative pricing advantage that has existed in recent years in favor of domestic natural gas prices (based on Henry Hub pricing). Increased regulation or difficulty in permitting of hydraulic fracturing, and any corresponding increase in domestic natural gas prices, could materially adversely affect demand for LNG and our ability to develop commercially viable LNG facilities.

We are subject to numerous governmental export laws and trade and economic sanctions laws and regulations. Our failure to comply with such laws and regulations could subject us to liability and have a material adverse impact on our business, results of operations or financial condition.

We conduct business throughout the world, and our business activities and services are subject to various applicable import and export control laws and regulations of the United States and other countries, particularly countries in the Caribbean, Ireland, Mexico, Nicaragua and the other countries in which we seek to do business. We must also comply with U.S. trade and economic sanctions laws, including the U.S. Commerce Department’s Export Administration Regulations and economic and trade sanctions regulations maintained by the U.S. Treasury Department’s Office of Foreign Assets Control. Although we take precautions to comply with all such laws and regulations, violations of governmental export control and economic sanctions laws and regulations could result in negative consequences to us, including government investigations, sanctions, criminal or civil fines or penalties, more onerous compliance requirements, loss of authorizations needed to conduct aspects of our international business, reputational harm and other adverse consequences. Moreover, it is possible that we could invest both time and capital into a project involving a counterparty who may become subject to sanctions. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations or otherwise, we may face an array of issues, including, but not limited to: having to abandon the related project, being unable to recuperate prior invested time and capital or being subject to law suits, investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties.

We are also subject to anti-corruption laws and regulations, including the U.S. Foreign Corrupt Practices Act (“FCPA”), which generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Some of the jurisdictions in which we currently, or may in the future, operate may present heightened risks for FCPA issues, such as Nicaragua, Jamaica, Mexico and Puerto Rico. Although we have adopted policies and procedures that are designed to ensure that we, our employees and other intermediaries comply with the FCPA, it is highly challenging to adopt policies and procedures that ensure compliance in all respects with the FCPA, particularly in high-risk jurisdictions. Developing and implementing policies and procedures is a complex endeavor. There is no assurance that these policies and procedures will work effectively all of the time or protect us against liability under anti-corruption laws and regulations, including the FCPA, for actions taken by our employees and other intermediaries with respect to our business or any businesses that we may acquire.

If we are not in compliance with anti-corruption laws and regulations, including the FCPA, we may be subject to costly and intrusive criminal and civil investigations as well significant potential criminal and civil penalties and other remedial measures, including changes or enhancements to our procedures, policies and control, as well as potential personnel change and disciplinary actions. In addition, non-compliance with anti-corruption laws could constitute a breach of certain covenants in operational or debt agreements, and cross-default provisions in certain of our agreements could mean that an event of default under certain of our commercial agreements could trigger an event of default under our other agreements, including our debt agreements. Any adverse finding against us could also negatively affect our relationship and reputation with current and potential customers. The occurrence of any of these events could have a material adverse impact on our business, results of operations, financial condition, liquidity and future business prospects.

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In addition, in certain countries we serve or expect to serve our customers through third-party agents and other intermediaries, such as customs agents. Violations of applicable import, export, trade and economic sanctions laws and regulations by these third-party agents or intermediaries may also result in adverse consequences and repercussions to us. There can be no assurance that we and our agents and other intermediaries will be in compliance with export control and economic sanctions laws and regulations in the future. In such event of non-compliance, our business and results of operations could be adversely impacted.

Risks Related to the Jurisdictions in Which We Operate

We are currently highly dependent upon economic, political and other conditions and developments in the Caribbean, particularly Jamaica, Puerto Rico and the other jurisdictions in which we operate.

We currently conduct a meaningful portion of our business in Jamaica and Puerto Rico. As a result, our current business, results of operations, financial condition and prospects are materially dependent upon economic, political and other conditions and developments in Jamaica and Puerto Rico.

We currently have interests and operations in Jamaica and the United States (including Puerto Rico) and currently intend to expand into additional markets in the Caribbean, Mexico, Ireland, Nicaragua and other geographies, and such interests are subject to governmental regulation in each market. The governments in these markets differ widely with respect to structure, constitution and stability and some countries lack mature legal and regulatory systems. To the extent that our operations depend on governmental approval and regulatory decisions, the operations may be adversely affected by changes in the political structure or government representatives in each of the markets in which we operate. Recent political, security and economic changes have resulted in political and regulatory uncertainty in certain countries in which we operate or may pursue operations. Some of these markets have experienced political, security and economic instability in the recent past and may experience instability in the future. In 2019, public demonstrations in Puerto Rico led to the governor’s resignation and the political change interrupted the bidding process for the privatization of PREPA’s transmission and distribution systems. While our operations were not, to date, impacted by the demonstrations or changes in Puerto Rico’s administration, any substantial disruption in our ability to perform our obligations under the Fuel Sale and Purchase Agreement with PREPA could have a material adverse effect on our financial condition, results of operations and cash flows. Furthermore, we cannot predict how our relationship with PREPA could change given PREPA’s award for its transmission and distribution system. PREPA may seek to find alternative power sources or purchase substantially less natural gas from us than what we currently expect to sell to PREPA.

Any slowdown or contraction affecting the local economy in a jurisdiction in which we operate could negatively affect the ability of our customers to purchase LNG, natural gas, steam or power from us or to fulfill their obligations under their contracts with us. If the economy in Jamaica, Puerto Rico or other jurisdictions in which we operate worsens because of, for example:

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lower economic activity, including as a result of the COVID-19 pandemic which has significantly affected Jamaica’s and other jurisdictions’ tourism industries;

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change in applicable laws;

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an increase in oil, natural gas or petrochemical prices;

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devaluation of the applicable currency;

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higher inflation; or

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an increase in domestic interest rates,

then our business, results of operations, financial condition and prospects may also be significantly affected by actions taken by the government in the jurisdictions in which we operate. The COVID-19 pandemic has resulted in lower economic activity and a decrease in oil prices worldwide. Certain of the jurisdictions in which we operate have recently restricted travel, implemented workforce pressures, and experienced reduced business development, travel, hospitality and tourism due to COVID-19. Caribbean governments traditionally have played a central role in the economy and continue to exercise significant influence over many aspects of it. They may make changes in policy, or new laws or regulations may be enacted or promulgated, relating to, for example, monetary policy, taxation, exchange controls, interest rates, regulation of banking and financial services and other industries, government budgeting and public sector financing. These and other future developments in the Jamaican economy or in the governmental policies in our Caribbean markets may reduce demand for our products and adversely affect our business, financial condition, results of operations or prospects.

For example, JPS and SJPC are subject to the mandate of the OUR. The OUR regulates the amount of money that power utilities in Jamaica, including JPS and SJPC, can charge their customers. Though the OUR cannot impact the fixed price we charge our customers for LNG, pricing regulations by the OUR and other similar regulators could negatively impact our customers’ ability to perform their obligations under our GSAs and, in the case of JPS, the PPA, which could adversely affect our business, financial condition, results of operations or prospects.

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Our development activities and future operations in Nicaragua may be materially affected by political, economic and other uncertainties.

Nicaragua has recently experienced political and economic challenges. Specifically, in 2018, U.S. legislation was approved to restrict U.S. aid to Nicaragua. In 2018, 2019 and 2020, U.S. and European governmental authorities imposed a number of sanctions against entities and individuals in or associated with the government of Nicaragua and Venezuela. If any of our counterparties becomes subject to sanctions as a result of these laws and regulations, changes thereto or otherwise, we may face an array of issues, including, but not limited to: having to suspend our development or operations on a temporary or permanent basis, being unable to recuperate prior invested time and capital or being subject to lawsuits, investigations or regulatory proceedings that could be time-consuming and expensive to respond to and which could lead to criminal or civil fines or penalties. There is also a risk of civil unrest, strikes or political turmoil in Nicaragua, and the outcome of any such unrest cannot be predicted.

Our financial condition and operating results may be adversely affected by foreign exchange fluctuations.

Our consolidated financial statements are presented in U.S. dollars. Therefore, fluctuations in exchange rates used to translate other currencies into U.S. dollars will impact our reported consolidated financial condition, results of operations and cash flows from period to period. These fluctuations in exchange rates will also impact the value of our investments and the return on our investments. Additionally, some of the jurisdictions in which we operate may limit our ability to exchange local currency for U.S. dollars.

A portion of our cash flows and expenses may in the future be incurred in currencies other than the U.S. dollar. Our material counterparties’ cash flows and expenses may be incurred in currencies other than the U.S. dollar. There can be no assurance that non-U.S. currencies will not be subject to volatility and depreciation or that the current exchange rate policies affecting these currencies will remain the same. We may choose not to hedge, or we may not be effective in efforts to hedge, this foreign currency risk. Depreciation or volatility of the Jamaican dollar against the U.S. dollar or other currencies could cause counterparties to be unable to pay their contractual obligations under our agreements or to lose confidence in us and may cause our expenses to increase from time to time relative to our revenues as a result of fluctuations in exchange rates, which could affect the amount of net income that we report in future periods.

We have operations in multiple jurisdictions and may expand our operations to additional jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated.

We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income and operations related to those jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing businesses and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.

Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect.

A change in tax laws in any country in which we operate could adversely affect us.

Tax laws, regulations and treaties are highly complex and subject to interpretation. Consequently, we are subject to changing laws, treaties and regulations in and between the countries in which we operate. Our tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, regulations, or treaties, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings.

Risks Related to Hygo’s Business Activities

Hygo has commenced commercial operations at one facility. Hygo’s other planned facilities are in various stages of contracting customers, construction, permitting and commissioning. There can be no assurance that Hygo’s planned facilities will commence operations timely, or at all.

Hygo’s Sergipe Facility commenced commercial operations in March 2020. However, Hygo has not yet commenced commercial operations or entered into binding construction contracts or obtained all necessary environmental, regulatory, construction and zoning permissions for any of its other facilities. Hygo may convert the Golar Celsius or the Golar Penguin into a FSRU to service its Barcarena Facility, but has not yet reached final investment decision for the deployment and conversion of such vessel. In addition, although Hygo has been awarded environmental and regulatory licenses for its Santa Catarina Facility, Hygo has not secured any commercial projects nor obtained all remaining necessary approvals. There can be no assurance that Hygo will be able to enter into the contracts required for the development of Hygo facilities on commercially favorable terms, if at all, or that Hygo will be able to obtain all of the environmental, regulatory, construction and zoning permissions Hygo needs in Brazil and elsewhere.

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In particular, Hygo will require agreements with ports proximate to its facilities capable of handling the transload of LNG direct from its occupying vessel to its transportation assets. If Hygo is unable to enter into favorable contracts or to obtain the necessary regulatory and land use approvals on favorable terms, Hygo may not be able to construct and operate these assets as anticipated, or at all. In addition, to develop future projects Hygo will, in many cases, have to secure the use of suitable vessels and, as required, convert them. Finally, the construction of facilities is inherently subject to the risks of cost overruns and delays. For example, the construction of Hygo’s Sergipe Power Plant experienced a two-month delay related to the installation of various offshore equipment.

If Hygo is unable to construct, commission and operate all of its facilities, or, when and if constructed, they do not accomplish their goals, or if Hygo experiences delays or cost overruns in construction, assuming the Hygo Merger has been consummated, our business, operating results, cash flows and liquidity could be materially and adversely affected. Expenses related to Hygo’s pursuit of contracts and regulatory approvals related to Hygo’s facilities still under development may be significant and will be incurred by Hygo regardless of whether these assets are ultimately constructed and operational.

There is no existing market in Brazil for the sale of LNG as a fuel source for trucking or vehicles generally. BR Distribuidora does not currently distribute, nor is obligated to commence distribution of, LNG through its distribution and fuel centers. Additionally, BR Distribuidora is not obligated to, and may not, convert any portion of its existing fleet of diesel trucks. Moreover, Hygo’s agreement with BR Distribuidora is subject to regulatory approval and other uncertainties. Hygo may be unable to realize the anticipated benefits of this partnership.

The transportation industry in Brazil currently relies on traditional fuels such as gasoline and diesel. And although there is wide acknowledgement in the industry that LNG represents a less expensive and more environmentally friendly alternative to these fuels, no significant portion of the transportation industry is currently utilizing LNG. Hygo cannot predict when, or even if, any meaningful portion of the transportation industry within Brazil will convert to LNG powered vehicles. Hygo’s agreement with Petrobras Distribuidora S.A. (“BR Distribuidora”) does not contractually obligate it to convert any portion of its fleet of diesel trucks to LNG-powered vehicles. Unless and until there is a significant conversion to LNG-powered vehicles within Brazil, Hygo will not realize the anticipated benefits of Hygo’s partnership, which could adversely impact Hygo’s, and assuming the consummation of the Merger, our future revenues.

In addition, Hygo’s activities with respect to the sale of LNG are subject to the approval of other regulatory authorities, including Agência Nacional de Petróleo, Gás Natural e Biocombustíveis (“ANP”). There can be no assurance as to whether regulatory approvals will be received or that they will be granted in a timely manner. Until Hygo receives these approvals, Hygo will be unable to make sales through BR Distribuidora’s distribution channels or other channels. Accordingly, Hygo has not yet made any sales pursuant to this arrangement.

Brazil and the Netherlands are conducting a joint investigation into allegations against Hygo’s former Chief Executive Officer, including allegations of improper payments made in Brazil. The outcome of this investigation could cause Hygo reputational harm or have a material adverse effect on Hygo’s business.

On September 23, 2020, Eduardo Antonello, Hygo’s former Chief Executive Officer, was named in a joint corruption investigation in Brazil and the Netherlands. Mauricio Carvalho, the majority shareholder of Evolution Power Partners S.A. (“Evolution”), Hygo’s joint venture partner in Centrais Elétricas Barcarena S.A. (“CELBA”), was also named in the investigation. In connection with the investigation, on September 23, 2020, Brazilian federal police executed search warrants on Hygo’s office in Brazil and certain of its joint ventures, and seized documents and electronic records and devices belonging to those entities relating to Mr. Antonello, Hygo and its joint ventures. On September 25, 2020, Hygo’s board of directors initiated an internal review with respect to Mr. Antonello’s conduct with respect to Hygo and its joint ventures. The board of directors was assisted in this review by outside counsel and accounting advisors. The review included forensic accounting work, review of certain contracts, interviews with certain company personnel and representatives, and review of internal audit material, certain corporate credit card expenses and Hygo’s anti-corruption policies. The board of directors of Hygo and its advisors did not identify any evidence establishing bribery or other corrupt conduct involving Hygo. In October 2020, before the review was completed, Mr. Antonello resigned as Chief Executive Officer and was replaced by Paul Hanrahan, who also joined the Hygo board of directors. The Hygo board of directors will continue its oversight and review of compliance procedures in accordance with the ethical and corporate governance standards established by applicable law.

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The investigation is ongoing and Hygo will continue to monitor its progress. While Hygo has conducted its own internal investigation and did not identify evidence establishing bribery or other corrupt conduct involving Hygo, Hygo cannot predict when the investigation will be completed or the results of the investigation, including whether any litigation will arise out of, relating to, or in connection with the investigation or the extent of the impact that the investigation or any such litigation may have on Hygo’s business. Publicity or other events associating with Mr. Antonello or the investigation, regardless of their foundation or accuracy, could adversely affect Hygo’s and our reputation and Hygo’s ability to conduct Hygo’s business in Brazil and other jurisdictions. For example, Hygo may experience difficulties participating in public auctions and in some cases, may be disqualified, as was the case with respect to Hygo’s bid to lease Petrobras’s Bahìa Regasification Terminal (the “Bahìa Facility”). On September 30, 2020, Hygo’s subsidiary, Golar Power Comercializadora de Gás Natural Ltda. (“Golar Power Comercializadora”), participated in a public competitive bid process sponsored by Petrobras for the lease of the Bahìa Terminal. Although Golar Power Comercializadora was the only qualifying participant to submit a bid, in October 2020, Petrobras notified all participants that Golar Power Comercializadora was disqualified. Golar Power Comercializadora subsequently filed an administrative appeal before the Petrobras Bid Committee challenging the final result of the competitive process. In December 2020, Golar Power Comercializadora lost the appeal and was not awarded the bid for the Bahìa Facility.

Hygo’s cash flow will be dependent upon the ability of its operating subsidiaries and joint ventures to make cash distributions to Hygo, the amount of which will depend on various factors.

Hygo currently anticipates that a major source of Hygo’s earnings will be cash distributions from Hygo’s operating subsidiaries and joint ventures. The amount of cash that Hygo’s operating subsidiaries and joint ventures can distribute each quarter to their owners, including Hygo, principally depends upon the amount of cash they generate from their operations, which will fluctuate from quarter to quarter based on, among other things:

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the amount of LNG or natural gas sold to customers;

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market price of LNG;

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the level of dispatch of the Sergipe Power Plant and Hygo’s future power plants;

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any restrictions on the payment of distributions contained in covenants in their financing arrangements and joint venture agreements;

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the levels of investments in each of Hygo’s operating subsidiaries, which may be limited and disparate;

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the levels of operating expenses, maintenance expenses and general and administrative expenses;

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regulatory action affecting: (i) the supply of, or demand for electricity in Brazil, (ii) operating costs and operating flexibility; and

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prevailing economic conditions.

Hygo’s facilities may be impacted by operational issues and delays. For example, in September 2020, the Sergipe Power Plant experienced transformer failures impacting its ability to dispatch at 100%, which have not yet been resolved. In addition, Hygo does not wholly own all of its operating subsidiaries and joint ventures. As a result, if such operating subsidiaries and joint ventures make distributions, including tax distributions, they will also have to make distributions to their noncontrolling interest owners.

Hygo may not be able to fully utilize the capacity of its facilities, which could impact its future revenues and materially harm Hygo’s business, financial condition and operating results.

Hygo’s FSRU facilities have significant excess capacity that is currently not dedicated to a particular anchor customer. Part of Hygo’s business strategy is to utilize undedicated excess capacity of Hygo’s FSRU facilities to serve additional downstream customers in the regions in which Hygo operates. However, Hygo has not secured, and Hygo may be unable to secure, commitments for all of its excess capacity. Factors which could cause Hygo to contract less than full capacity include difficulties in negotiations with potential counterparties and factors outside of its control such as the price of and demand for LNG. Failure to secure commitments for less than full capacity could impact Hygo’s future revenues and materially harm Hygo’s business, financial condition and operating results.

In addition, the operator of the Sergipe Facility, Centrais Elétricas de Sergipe S.A. (“CELSE”) (which is an entity wholly owned by Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”), a 50/50 joint venture between Hygo and Ebrasil Energia Ltda. (“Ebrasil”)), has the right to utilize 100% of the capacity at Hygo’s Sergipe Facility pursuant to the Sergipe FSRU Charter. In order to utilize the excess capacity of the Sergipe Facility, Hygo will need the consent of CELSE and the senior lenders under CELSE’s financing arrangements. If Hygo is unable to obtain the necessary consents to utilize the excess capacity of the Sergipe Facility, Hygo’s business, financial condition and operating results may be adversely affected.

Failure of LNG to be a competitive source of energy in the markets in which Hygo operates, and seeks to operate, could adversely affect Hygo’s expansion strategy.

Hygo’s operations are, and will be, dependent upon LNG being a competitive source of energy in the markets in which Hygo operates. In particular, hydroelectric power generation is the predominant source of electricity in Brazil and LNG is one of several other energy sources used to supplement hydroelectric generation. Potential expansion in other parts of world where Hygo may operate is primarily dependent upon LNG being a competitive source of energy in those geographical locations. Likewise, recent declines in the cost of crude oil, if sustained, will make crude oil and its derivatives a more competitive fuel source to LNG.

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As a result of these and other factors, natural gas may not be a competitive source of energy in the markets Hygo intends to serve or elsewhere. The failure of natural gas to be a competitive supply alternative to oil and other alternative energy sources could adversely affect Hygo’s ability to deliver LNG or natural gas to Hygo’s customers or other locations on a commercial basis.

CELSE is subject to risk of loss or damage to LNG that is processed and/or stored at its FSRUs and transported via pipeline.

LNG processed and stored on FSRUs may be subject to loss or damage resulting from equipment malfunction, faulty handling, ageing or otherwise. For the period of time during which LNG is stored on an FSRU or is dispatched to a pipeline, CELSE, in the case of the Sergipe Facility, bears the risk of loss or damage to all such LNG. Any such disruption to the supply of LNG and natural gas may lead to delays, disruptions or curtailments in the production of power at the Sergipe Power Plant. If CELSE cannot generate energy at the Sergipe Power Plant by burning natural gas, Hygo’s, and, after consummation of the Hygo Merger, our revenues, financial condition and results of operations may be materially and adversely affected.

Hygo has a limited operating history and anticipates significant capital expenditures.

Hygo commenced operations in May 2016 and has a limited operating history and track record. As a result, its prior operating history and historical consolidated financial statements may not be a reliable basis for evaluating its business prospects. In addition, Hygo has historically derived its revenues from the operation of its vessels on short-term charters, but Hygo expects the majority of its future revenues to be derived from its LNG-to-power projects. Hygo’s strategy may not be successful, and if unsuccessful, it may be unable to modify it in a timely and successful manner. Hygo cannot give any assurance that it will be able to implement its strategy on a timely basis, if at all, or achieve its internal model or that its assumptions will be accurate. Hygo’s limited history also means that it continues to develop and implement various policies and procedures including those related to data privacy and other matters. Hygo will need to continue to build its team to implement its strategies.

Hygo will continue to incur significant capital and operating expenditures while it develops its network of downstream LNG infrastructure, including for the completion of the Barcarena Facility, the Santa Catarina Facility and other projects in Brazil currently under construction, as well as other future projects. Hygo will need to invest significant amounts of additional capital to implement its strategy. Hygo has not completed constructing all of its facilities and its strategy includes the construction of additional facilities. Any delays beyond the expected development period for these assets would prolong, and could increase the level of, operating losses and negative operating cash flows. Hygo’s future liquidity may also be affected by the timing of construction financing availability in relation to the incurrence of construction costs and other outflows and by the timing of receipt of cash flows under its customer contracts in relation to the incurrence of project and operating expenses. Hygo’s ability to generate any positive operating cash flow and achieve profitability in the future is dependent on, among other things, its ability to successfully and timely complete necessary infrastructure, including its Barcarena and Santa Catarina Terminals and other projects in Brazil currently under construction, and fulfill its delivery obligations under its customer contracts.

Hygo’s power generation projects may depend on the construction and operation of transmission and interconnection facilities by third parties.

Hygo’s power generation projects must interconnect to Brazil’s transmission system and such projects may depend on the completion of new lines and/or increases in the capacity of existing facilities by the applicable power transmission concessionaires in order to interconnect and become fully operational. Delays from such concessionaires in the completion of the necessary interconnection and associated facilities may affect the ability of Hygo’s power generation projects to start commercial operation and/or fulfill power delivery commitments under the PPAs.

Hygo’s ability to dispatch electricity from its power plants is dependent upon hydrological and other grid conditions in Brazil.

Historically, Brazil’s electricity generation has been dominated by hydroelectricity plants. There are substantial seasonal variations in monthly and annual flows to the plants, which depend fundamentally on the volume of rain that falls in each rainy season. When hydrological conditions are poor, the National Electricity System Operator (Operador Nacional do Sistema, or “ONS”) dispatches thermoelectric power plants, including those that Hygo operates, to top up hydroelectric generation and maintain the electricity supply level.

The ONS Grid Code allows the ONS to dispatch thermoelectric power plants for the following reasons or under the following circumstances:

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when marginal operation cost is the same as the variable unit cost of such power plant;

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due to inflexibility or necessity of the generator;

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when dispatch of such power plant is needed in order to maintain the stability of the system;

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as determined by the Energy Industry Monitoring Committee where extraordinary circumstances exist;

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due to accelerated and/or replacement generation as proposed by the generator in order to make up for the unavailability of fuel; and

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for purposes of exportation of power to foreign markets.

As a result, the amount of electricity generated by thermoelectric power plants, including Hygo’s power plants that are already contracted and its power plants under development, can vary significantly in response to the hydrological and other grid conditions in Brazil. If Hygo’s power plants are not dispatched or are dispatched at levels lower than expected, its operations and financial results may be adversely affected.

Hygo may not be profitable for an indeterminate period of time.

Hygo has a limited operating history and did not commence revenue-generating activities until 2016, and therefore did not achieve profitability as of December 31, 2020. Hygo will need to make a significant capital investment to construct and begin operations of the Barcarena Terminal, the Santa Catarina Terminal, its downstream distribution hubs and its other LNG-to-power projects in Brazil, and Hygo will need to make significant additional investments to develop, improve and operate them, as well as all related infrastructure. Hygo also expects to make significant expenditures and investments in identifying, acquiring and/or developing other future projects. Hygo also expects to incur significant expenses in connection with the launch and growth of its business, including costs for LNG purchases, rail and truck transportation, shipping and logistics and personnel. Hygo will need to raise significant additional debt and/or equity capital to achieve its goals. Hygo may not be able to achieve profitability, and if it does, Hygo cannot assure you that it would be able to sustain such profitability in the future.

Hygo’s operational and consolidated financial results are partially dependent on the results of the joint ventures, affiliates and special purpose entities in which it invests.

Hygo conducts its business mainly through its operating subsidiaries. In addition, Hygo and its subsidiaries conduct some of their business through joint venture and other special purpose entities, which are created specifically to participate in public auctions for enterprises in the generation and transmission segments. Hygo’s ability to meet its financial obligations is therefore related in part to the cash flow and earnings of its subsidiaries and joint ventures and the distribution or other transfers of earnings to Hygo in the form of dividends, loans or other advances and payments that are governed by various joint venture financing and operating arrangements.

Hygo has entered into joint ventures, and may in the future enter into additional or modify existing joint ventures, that might restrict its operational and corporate flexibility.

Hygo entered into joint ventures to acquire and develop LNG infrastructure projects and may in the future enter into additional joint venture arrangements with third parties. As Hygo does not operate the assets owned by these joint ventures, its control over their operations is limited by provisions of the agreements it has entered into with its joint venture partners and by its percentage ownership in such joint ventures. Because Hygo does not control all of the decisions of its joint ventures, it may be difficult or impossible for Hygo to cause the joint venture to take actions that Hygo believes would be in its or the joint venture’s best interests. For example, Hygo cannot unilaterally cause the distribution of cash by its joint ventures. Additionally, as the joint ventures are separate legal entities, any right Hygo may have to receive assets of any joint venture or other payments upon their liquidation or reorganization will be effectively subordinated to the claims of the creditors of that joint venture (including tax authorities and trade creditors). Moreover, joint venture arrangements involve various risks and uncertainties, such as committing Hygo to fund operating and/or capital expenditures, the timing and amount of which it may not control, and its joint venture partners may not satisfy their financial obligations to the joint venture. Hygo’s results of operations depend on the performance of these joint ventures and their ability to distribute funds to Hygo, and Hygo may be unable to control the amount of cash it will receive from their operations or the timing of capital expenditures, which could adversely affect its financial condition.

Hygo may guarantee the indebtedness of its joint ventures and/or affiliates.

Hygo may provide guarantees to certain banks with respect to commercial bank indebtedness of its joint ventures and/or affiliates. Failure by any of its joint ventures, equity method investees and/or affiliate to service their debt requirements and comply with any provisions contained in their commercial loan agreements, including paying scheduled installments and complying with certain covenants, may lead to an event of default under the related loan agreement. As a result, if Hygo’s joint ventures, equity method investees and/or affiliates are unable to obtain a waiver or do not have enough cash on hand to repay the outstanding borrowings, the relevant lenders may foreclose their liens on the vessels securing the loans or seek repayment of the loan from Hygo, or both. Either of these possibilities could have a material adverse effect on Hygo’s business. Further, by virtue of Hygo’s guarantees with respect to Hygo’s joint ventures and/or affiliates, this may reduce its ability to gain future credit from certain lenders.

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Hygo is dependent upon GLNG and its affiliates for the operation and maintenance of its vessels.

Each of Hygo’s vessels is operated and maintained by GLNG or its affiliates pursuant to ship management agreements. These agreements are the result of arms-length negotiations and subject to change. In addition, we expect to enter into management agreements with GLNG or its affiliates with respect to Hygo's vessels concurrently with the closing of the Hygo Merger. If GLNG or any of its affiliates that provide services to Hygo fails to perform these services satisfactorily or the terms of the ship management agreements change now or after the consummation of the Proposed Mergers, it could have a material adverse effect on Hygo’s or, after the consummation of the Hygo Merger, our, business, results of operations and financial condition.

Hygo may not be able to purchase or receive physical delivery of natural gas or LNG in sufficient quantities and/or at economically attractive prices to supply the Sergipe Power Plant and satisfy its delivery obligations under the PPAs, which could have a material adverse effect on Hygo.

Under the PPAs related to the Sergipe Power Plant and its other LNG-to-power facilities, Hygo is required to deliver power, which also requires Hygo to obtain sufficient amounts of LNG. However, Hygo may not be able to purchase or receive physical delivery of sufficient quantities of LNG to satisfy those delivery obligations, which may subject Hygo to certain penalties and provide its counterparties with the right to terminate their PPAs. With respect to the Sergipe Power Plant, Hygo has entered into a supply agreement with Ocean LNG, an affiliate of Qatar Petroleum. If Ocean LNG fails to deliver sufficient LNG to Sergipe, Hygo would be forced to purchase LNG on the spot market, which may be on less favorable terms. In addition, price fluctuations in natural gas and LNG may make it expensive or uneconomical for Hygo to acquire adequate supply of these items for its other customers.

Hygo is dependent upon third party LNG suppliers and shippers and other tankers and facilities to provide delivery options to and from its tankers and energy-related infrastructure. If LNG were to become unavailable for current or future volumes of natural gas due to repairs or damage to supplier facilities or tankers, lack of capacity, impediments to international shipping or any other reason, Hygo’s ability to continue delivering natural gas, power or steam to end-users could be restricted, thereby reducing its revenues. Additionally, under tanker charters, Hygo will be obligated to make payments for its chartered tankers regardless of use. Hygo may not be able to enter into contracts with purchasers of LNG in quantities equivalent to or greater than the amount of tanker capacity it has purchased. If any third parties were to default on their obligations under Hygo’s contracts or seek bankruptcy protection, Hygo may not be able to purchase or receive a sufficient quantity of natural gas in order to supply the Sergipe Power Plant and satisfy its delivery obligations under its PPAs. Any permanent interruption at any key LNG supply chains that caused a material reduction in volumes transported to Hygo’s facilities could have a material adverse effect on its business, financial condition, operating results, cash flow, liquidity and prospects.

Recently, the LNG industry has experienced increased volatility. If market disruptions and bankruptcies of third party LNG suppliers and shippers negatively impacts Hygo’s ability to purchase a sufficient amount of LNG or significantly increases its costs for purchasing LNG, its business, operating results, cash flows and liquidity could be materially and adversely affected.

Under certain circumstances, Hygo may be required to make payments under its gas supply agreements.

If Hygo fails to take delivery of contracted volumes under its gas supply agreements, it may be required to make payments to counterparties under such agreements. For example, CELSE entered into a 25-year LNG supply agreement with Ocean LNG for the supply of LNG to the Sergipe Terminal. Pursuant to the terms of the Sergipe Supply Agreement, CELSE is required to take delivery of a specified base quantity of LNG each year, subject to certain adjustments. If CELSE takes less than the full number of scheduled cargoes per year under the Sergipe Supply Agreement, CELSE will be required to pay Ocean LNG a cancellation fee per cargo according to a formula based on the number of the cargoes not taken, subject to a cap over every five-year period and the full 25 year term.

Hygo’s current lack of asset and geographic diversification could have an adverse effect on its business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The substantial majority of Hygo’s anticipated revenue in the future will be dependent upon its assets and customers in Brazil. Brazil has historically experienced economic volatility and the general condition and performance of the Brazilian economy, over which Hygo has no control, may affect its business, financial condition and results of operations. Due to its current lack of asset and geographic diversification, an adverse development at any of its facilities in Brazil, in the energy industry or in the economic conditions in Brazil, would have a significantly greater impact on Hygo’s financial condition and operating results than if it maintained more diverse assets and operating areas.

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Hygo’s operations could be limited or restricted in order to comply with protections for indigenous populations located in the areas in which it operates, and could also be adversely impacted by any changes in Brazilian law to comply with certain requirements embodied in international treaties and other laws related to indigenous communities.

Indigenous communities—including, in Brazil, Afro-indigenous (“Quilombola”) communities—are subject to certain protections under international and national laws. There are several indigenous communities that surround its operations in Brazil. Hygo has entered into agreements with some of these communities that mainly provide for the use of their land for its operations, and negotiations with other such communities are ongoing. In the event that Hygo is unable to reach an agreement with indigenous communities, that its relationship with these communities deteriorates in future, or that such communities do not comply with any existing agreements related to Hygo’s operations, it could have a material adverse effect on Hygo’s business and results of operations.

Brazil has ratified the International Labor Organization’s Indigenous and Tribal Peoples Convention (“ILO Convention 169”), which is grounded on the principle of consultation and participation of indigenous and traditional communities under the basis of free, prior, and informed consent (“FPIC”). ILO Convention 169 sets forth that governments are to ensure that members of tribes directly affected by legislative or administrative measures, including the grant of government authorizations such as are required for Hygo’s operations, are consulted through appropriate procedures and through their representative institutions. ILO Convention 169 further states that the consultation must be undertaken aiming at achieving an agreement or consent to the proposed legislative or administrative measures.

Brazilian law does not specifically regulate the FPIC process for indigenous and traditional people affected by undertakings, nor does it set forth that individual members of an affected community shall render their FPIC on an undertaking that may impact them. However, in order to obtain certain environmental licenses for Hygo’s operations, Hygo is required to comply with the requirements of, consult with, and obtain certain authorizations from a number of institutions regarding the protection of indigenous interests: the National Congress (in specific cases), the Federal Public Prosecutor’s Office and the National Indian Foundation (Fundação Nacional do Índio or FUNAI) (for indigenous people) or Palmares Cultural Foundation (Fundação Cultural Palmares) (for Quilombola communities). If Hygo is not able to timely obtain the necessary authorizations or obtain them on favorable terms for its operations in areas where indigenous communities reside, Hygo could face construction delays, increased costs, or otherwise experience adverse impacts on its business and results of operations.

Additionally, the American Convention on Human Rights (“ACHR”), to which Brazil is a party, sets forth rights and freedoms prescribed for all persons, including property rights without discrimination due to race, language, and national or social origin. The ACHR also provides for consultation with indigenous communities regarding activities that may affect the integrity of their land and natural resources. If Brazil’s legal process for consultation and the protection of indigenous rights is challenged under the ACHR and found to be inadequate, it could result in orders or judgments that could ultimately adversely impact its operations. For example, in February 2020, the Interamerican Court of Human Rights (“IACtHR”) found that Argentina had not taken adequate steps, in law or action, to ensure the consulting of indigenous communities and obtaining those communities’ free prior and informed consent for a project impacting their territories. IACtHR further found that Argentina had thus violated the ACHR due to infringements on the indigenous communities’ rights to property, cultural identity, a healthy environment, and adequate food and water by failing to take effective measures to stop harmful, third-party activities on the indigenous communities’ traditional land. As a result, IACtHR ordered Argentina, among other things, to achieve the demarcation and grant of title to the indigenous communities over their territory and the removal of the third-parties from the indigenous territory. Hygo cannot predict whether this decision will result in challenges regarding the adequacy of existing Brazilian legal requirements related to the protection of indigenous rights, changes to the existing Brazilian government body consultation process, or impact its existing development agreements or its negotiations for outstanding development agreements with indigenous communities in the areas in which it operates. However, if the consultations with indigenous communities potentially impacted by Hygo’s operations are found to be insufficient, Hygo could experience a material adverse impact to its business and results of operations.

Hygo is subject to comprehensive regulation of its business, which fundamentally affects its financial performance.

Hygo’s business is subject to extensive regulation by various Brazilian regulatory authorities, particularly Agência Nacional de Energia Elétrica (“ANEEL”), ANP and Agência Nacional de Transportes Aquaviários (“ANTAQ”). ANEEL regulates and oversees various aspects of Hygo’s business and establishes its tariffs. If Hygo is obligated by ANEEL to make additional and unexpected capital investments and is not allowed to adjust its tariffs accordingly, if ANEEL does not authorize the recovery of all costs or if ANEEL modifies the regulations related to tariff adjustments, Hygo may be adversely affected. ANP regulates the import and export of LNG and the transportation and distribution of natural gas activities, including Hygo’s downstream distribution business. ANTAQ regulates and oversees port activities in Brazil.

In addition, both the implementation of Hygo’s strategy for growth and its ordinary business may be adversely affected by governmental actions such as changes to current legislation, the termination of federal and state concession programs, creation of more rigid criteria for qualification in public energy auctions, or a delay in the revision and implementation of new annual tariffs.

If regulatory changes require Hygo to conduct its business in a manner substantially different from its current operations, Hygo’s operations, financial results and its capacity to fulfill its contractual obligations may be adversely affected.

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CELSE and CELBA could be penalized by ANEEL for failing to comply with the terms of their respective authorizations and applicable legislation and CELSE and CELBA may not recover the full value of their respective investments if such authorizations are terminated.

CELSE and CELBA will carry out their respective power generation activities in accordance with the authorizations granted by the Brazilian government through the MME (the ‘‘MME Authorizations”). CELSE’s authorization expires in November 2050, and CELBA’s authorization, which is in the process of being granted, is expected to expire in 2055. ANEEL may impose penalties on CELSE and CELBA if they fail to comply with any provision of the MME Authorizations or with the legislation and regulations applicable to the Brazilian power industry. Depending on the extent of the non-compliance, these penalties could include:

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warnings;

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substantial fines (in some cases up to 2% of gross revenues arising from the generation activity in the 12-month period immediately preceding the assessment);

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prohibition on operations;

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bans on the construction of new facilities or the acquisition of new projects;

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restrictions on the operation of existing facilities and projects; or

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restrictions on operations (including the exclusion from participating in upcoming auctions), temporary suspension of participation in auctions and bidding processes for new concessions and authorizations.

ANEEL may also terminate the MME Authorizations prior to their expiration in the event that CELSE or CELBA fails to comply with the provisions of the MME Authorizations, is declared bankrupt or is dissolved. In the event of non-compliance by CELSE and/or CELBA, ANEEL may also impose certain of the penalties (in particular, bans and restrictions) on affiliates of CELSE and CELBA.

CELSE and CELBA are subject to extensive legislation and regulations imposed by the Brazilian government and ANEEL, and cannot predict the effect of any changes to the legislation or regulations currently in force regarding their respective businesses.

The implementation of Hygo’s business strategy and its ability to carry out its activities may be adversely affected by certain governmental actions.

Hygo may be subject to new regulations enacted by the Brazilian government that could retroactively affect the rules for renewal of its concessions and authorizations.

The non-renewal of any of Hygo’s authorizations, as well as the non-renewal of its energy supply contracts, could have a material adverse effect on its financial condition, results of operations and Hygo’s capacity to fulfill its contractual obligations.

The regulatory framework under which Hygo operates is subject to legal challenge.

The Brazilian government implemented fundamental changes in the regulation of the power industry in legislation passed in 2004 known as the Lei do Novo Modelo do Setor Elétrico, or New Regulatory Framework. Challenges to the constitutionality of the New Regulatory Framework are still pending before the Brazilian Federal Supreme Court (Supremo Tribunal Federal), although preliminary injunctions have been dismissed. It is not possible to estimate when these proceedings will be finally decided. If all or part of the New Regulatory Framework were held to be unconstitutional, there would be uncertain consequences for the validity of existing regulation and the further development of the regulatory framework. The outcome of the legal proceedings is difficult to predict, but it could have an adverse impact on the entire energy sector, including Hygo’s business and results of operations. Due to the duration of the lawsuit, it is possible that the Brazilian Federal Supreme Court will not give retroactive effect to its decision, but rather preserve the validity of past acts applying a judicial practice known as modulation of effects.

If the regulatory framework under which Hygo operates is revised in a way that results in Hygo being required to conduct its business in a manner substantially different from its current operations, Hygo’s operations, financial results and capacity to fulfill its contractual obligations may be adversely affected.

Commercialization activity is subject to potential losses due to short-term variations in energy prices on the spot market.

Hygo’s sales on the spot market are subject to potential differences in the settlement between the energy delivered and the energy sold. The differences are settled by the Câmara de Comercialização de Energia Elétrica (the Electric Energy Trading Chamber) at the spot price, or the PLD. The PLD is based on the energy traded in the spot energy market. It is calculated for each submarket and load level on a weekly basis and is based on the marginal cost of operation. The maximum and the minimum value of the PLD are set every year by ANEEL. Short-term variations in energy prices on the spot energy market may lead to potential losses in Hygo’s commercialization activity.

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Hygo is uncertain as to the review of the Physical Guarantee of its generation power plants.

The “Physical Guarantee” is the amount of power that a plant is expected to contribute to the electricity grid over the life of a PPA. Hygo cannot be certain if future events could affect the Physical Guarantee of each of its individual power plants. When the Physical Guarantee of a power plant is decreased, Hygo’s ability to supply electricity under that plant’s PPAs is adversely affected, which can lead to a decrease in Hygo’s revenues and increase Hygo’s costs if its generation subsidiaries are required to purchase power elsewhere. Damage to the step up transformer and related equipment at the Sergipe Power Plant in September 2020 is expected to temporarily decrease the Sergipe Power Plant’s Physical Guarantee by 8.75 MWh per year. To the extent CELSE is required to dispatch before repairs to the transformer and related equipment are complete, CELSE could be required to purchase the difference between its committed output and the final available power for delivery to PPA customers for the length of the requested dispatch period.

Hygo is currently highly dependent upon economic, political, regulatory and other conditions and developments in Brazil.

Hygo currently conducts a meaningful portion of its business in Brazil. As a result, Hygo’s current business, results of operations, financial condition and prospects are materially dependent upon economic, political and other conditions and developments in Brazil. For example, on July 8, 2019, Petróleo Brasileiro S.A. – Petrobras (“Petrobras”) the state-owned oil company in Brazil, entered into an agreement (Termo de Compromisso de Cessão de Prática) with Brazilian antitrust authorities (Conselho Administrativo de Defesa Econômica - CADE) pursuant to which it has agreed to divest its equity participation in the gas pipelines and state gas distribution companies in Brazil by December 31, 2021. Such divestment plan, intended to end Petrobras’s monopoly on the distribution of gas in Brazil, will increase competition and may affect Hygo’s business.

In particular, the Brazilian economy has been characterized by frequent and occasionally extensive intervention by the Brazilian government and unstable economic cycles. The Brazilian government has often changed monetary, taxation, credit, tariff and other policies to influence the course of Brazil’s economy. The Brazilian government’s actions to control inflation and implement other policies have at times involved wage and price controls, blocking access to bank accounts, imposing capital controls and limiting imports into Brazil. In addition, Brazilian markets and politics have been characterized by considerable instability in recent years due to uncertainties derived from the ongoing corruption investigations such as Operation Car Wash, the conviction of Former President Luiz Inácio Lula da Silva, the impeachment of Former President Dilma Rousseff and the election of Congressman Jair Bolsonaro. The spread of COVID-19 in Brazil has resulted in heightened uncertainty and political instability as government officials debate appropriate response measures. These uncertainties and any measures adopted by the new administration may increase market volatility and political instability.

Hygo’s sale and leaseback agreements contain restrictive covenants that may limit its liquidity and corporate activities, and could have an adverse effect on its financial condition and results of operations.

Hygo’s sale and leaseback agreements for the Golar Nanook, Golar Penguin and Golar Celsius contain, and any future sale and leaseback agreements it may enter into are expected to contain, customary covenants and event of default clauses, including cross-default provisions and restrictive covenants and performance requirements that may affect Hygo’s operational and financial flexibility. In addition, Hygo also assigns the shares in its subsidiaries which are the charterers of these vessels to the owners/lessors. Such restrictions could affect, and in many respects limit or prohibit, among other things, its ability to incur additional indebtedness, create liens, sell assets, or engage in mergers or acquisitions. These restrictions could also limit Hygo’s ability to plan for or react to market conditions or meet extraordinary capital needs or otherwise restrict corporate activities. There can be no assurance that such restrictions will not adversely affect its ability to finance its future operations or capital needs.

Certain of Hygo’s sale and leaseback agreements contain cross-default clauses and require it to maintain specified financial ratios, satisfy certain financial covenants and/or assign equity interests in its subsidiaries to third parties, including, among others, the following requirements:

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that Hygo maintains Free Liquid Assets (as defined in the Penguin Leaseback) of at least $50.0 million; and

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that Hygo assigns the shares in each of Golar Hull M2026 Corp., Golar Hull M2023 Corp. and Golar FSRU 8 Corp., its subsidiaries that are the charterers under Hygo’s sale and leaseback agreements, to the applicable vessel owners.

As of December 31, 2020, Hygo was in compliance with the consolidated leverage ratio and the minimum free liquidity covenants in its sale and leaseback agreements.

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As a result of the restrictions in its sale and leaseback agreements, or similar restrictions in future sale and leaseback agreements, Hygo may need to seek permission from the owners of its leased vessels in order to engage in certain corporate actions. Their interests may be different from Hygo’s and Hygo may not be able to obtain their permission when needed. This may prevent Hygo from taking actions that it believes are in its best interest, which may adversely impact Hygo’s revenues, results of operations and financial condition.

A failure by Hygo to meet its payment and other obligations, including its financial covenant requirements, could lead to defaults under its sale and leaseback agreements or any future sale and leaseback agreements. If Hygo is not in compliance with its covenants and is not able to obtain covenant waivers or modifications, the current or future owners of its leased vessels, as appropriate, could retake possession of the vessels or require Hygo to pay down its indebtedness to a level where Hygo is in compliance with its covenants or sell vessels in its fleet. Hygo could lose its vessels if it defaults on its bareboat charters in connection with the sale and leaseback agreements, which would negatively affect Hygo’s revenues, results of operations and financial condition.

There are risks and uncertainties relating to Hygo’s sale and leaseback transactions.

On closing of its sale and leaseback transactions, Hygo transferred its ownership interests in each of the Golar Nanook, the Golar Penguin and the Golar Celsius. Although the operation of these vessels is expected to continue in the ordinary course, the bareboat charters in connection with the sale and leaseback transactions may, in certain circumstances, be terminated. Any such termination could have a significant adverse effect on Hygo’s business, financial condition and results of operations of its vessels. The sale and leaseback agreements will also require significant periodic cash payments in respect of the required rent thereunder, which Hygo has not historically incurred for the Golar Celsius or, prior to December 2019, the Golar Penguin, and other allocated operating and maintenance costs. The increase in Hygo’s lease expense may have an adverse impact on its future operations and profitability.

Risks Related to GMLP Business Activities

GMLP currently derives all of its revenue from a limited number of customers. The loss of any of its customers would result in a significant loss of revenues and cash flow, if it is unable to re-charter a vessel to another customer for an extended period of time.

GMLP’s fleet consists of six FSRUs, four LNG carriers and an interest in the Hilli. GMLP has derived, and believes that it will continue to derive, all of its revenues and cash flow from a limited number of customers. The majority of its charters have fixed terms, but might nevertheless be lost in the event of unanticipated developments such as a customer’s breach. The ability of each of GMLP’s customers to perform its respective obligations under a charter with GMLP will depend on a number of factors that are beyond its control and may include, among other things, general economic conditions, the condition of the LNG shipping industry, prevailing prices for natural gas and LNG, the impact of COVID-19 and similar pandemics and epidemics and the overall financial condition of the counterparty. GMLP could also lose a customer or the benefits of a charter if the customer fails to make charter payments because of its financial inability, disagreements with GMLP or otherwise or the customer exercises its right to terminate the charter in certain circumstances.

If GMLP loses any of its charterers and are unable to re-deploy the related vessel for an extended period of time, it will not receive any revenues from that vessel, but it will be required to pay expenses necessary to maintain the vessel in seaworthy operating condition and to service any associated debt. In addition, it is an event of default under the credit facilities related to all of GMLP’s vessels if the time charter of any vessel related to any such credit facility is cancelled, rescinded or frustrated and it is unable to secure a suitable replacement charter, post additional security or make certain significant prepayments. Any event of default under GMLP’s credit facilities would result in acceleration of amounts due thereunder. GMLP will be required to provide additional security or make prepayments under its $800 million credit facility in the event that the charter in respect of the Golar Winter is terminated early and it cannot find an alternative acceptable charter. In addition, under the sale and leaseback arrangement in respect of the Golar Eskimo, if the time charter pursuant to which the Golar Eskimo is operating is terminated, the owner of the Golar Eskimo (which is a wholly-owned subsidiary of China Merchants Bank Leasing) will have the right to require GMLP to purchase the vessel from it unless GMLP is able to place such vessel under a suitable replacement charter within 24 months of the termination. GMLP may not have, or be able to obtain, sufficient funds to make these accelerated payments or prepayments or be able to purchase the Golar Eskimo. In such a situation, the loss of a charterer could have a material adverse effect on GMLP’s business, results of operations and financial condition.

GMLP’s business strategy depends on its ability to expand relationships with existing customers and obtain new customers, for which it will face substantial competition.

GMLP’s principal strategy is to provide steady and reliable shipping, regasification and liquefaction operations for its customers. The process of obtaining long-term charters for FSRUs and LNG carriers is highly competitive and generally involves an intensive screening process and competitive bids, and often extends for several months. GMLP believes FSRU and LNG carrier time charters are awarded based upon bid price as well as a variety of factors relating to the vessel operator, including:

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its FSRU and LNG shipping experience, technical ability and reputation for operation of highly specialized vessels;

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its shipping industry relationships and reputation for customer service and safety;

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the quality and experience of its seafaring crew;

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its financial stability and ability to finance FSRUs and LNG carriers at competitive rates;

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its relationships with shipyards and construction management experience; and

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its willingness to accept operational risks pursuant to the charter.

GMLP faces substantial competition for providing FSRU and marine transportation services for potential LNG projects from a number of experienced companies, including state-sponsored entities and major energy companies. Many of these competitors have significantly greater financial resources and larger and more versatile fleets than GMLP. GMLP anticipates that an increasing number of marine transportation companies, including many with strong reputations and extensive resources and experience will enter the FSRU market and the LNG transportation market. This increased competition may cause greater price competition for time charters. As a result of these factors, GMLP may be unable to expand its relationships with existing customers or to obtain new customers on a favorable basis, if at all, which would have a material adverse effect on its business, results of operations and financial condition.

GMLP’s future long-term charter revenue depends on its competitive position and future hire rates for FSRUs and LNG carriers.

One of GMLP’s principal strategies is to enter into new long-term FSRU and LNG carrier time charters and to replace expiring charters with similarly long-term contracts. Most requirements for new LNG projects continue to be provided on a long-term basis, though the level of spot voyages and short-term time charters of less than 12 months in duration together with medium term charters of up to five years has increased in recent years. This trend is expected to continue as the spot market for LNG expands. More frequent changes to vessel sizes and propulsion technology together with an increasing desire by charterers to access modern tonnage could also reduce the appetite of charterers to commit to long-term charters that match their full requirement period. As a result, the duration of long-term charters could also decrease over time.

GMLP may also face increased difficulty entering into long-term time charters upon the expiration or early termination of its contracts. If as a result GMLP contracts its vessels on short-term contracts, its earnings from these vessels are likely to become more volatile. An increasing emphasis on the short-term or spot LNG market may in the future require that GMLP enter into charters based on variable market prices, as opposed to contracts based on a fixed rate, which could result in a decrease in its cash flow in periods when the market price for shipping LNG is depressed or insufficient funds are available to cover its financing costs for related vessels.

Hire rates for FSRUs and LNG carriers may fluctuate substantially. If rates are lower when GMLP is seeking a new charter, its earnings may decline.

Hire rates for FSRUs and LNG carriers fluctuate over time as a result of changes in the supply-demand balance relating to current and future FSRU and LNG carrier capacity. This supply-demand relationship largely depends on a number of factors outside GMLP’s control. For example, driven in part by an increase in LNG production capacity, the market supply particularly of LNG carriers has been increasing. As of March 2, 2021, the LNG carrier order book totaled 141 vessels. GMLP believes that this and any future expansion of the global LNG carrier fleet may have a negative impact on charter hire rates, vessel utilization and vessel values, the impact of which could be amplified if the expansion of LNG production capacity does not keep pace with fleet growth. The LNG market is also closely connected to world natural gas prices and energy markets, which it cannot predict. A substantial or extended decline in demand for natural gas or LNG, including as a result of the spread of COVID-19, could adversely affect GMLP’s ability to charter or re-charter its vessels at acceptable rates or to acquire and profitably operate new vessels. Accordingly, this could have a material adverse effect on its earnings.

The charterers of two of GMLP’s vessels have the option to extend the charter at a rate lower than the existing hire rate. The exercise of these options could have a material adverse effect on its cash flow.

The charterers of the NR Satu and Methane Princess have options to extend their respective existing contracts. If they exercise these options, the hire rate for the NR Satu will be reduced by approximately 12% per day for any day in the extension period falling in 2023, with a further 7% reduction for any day in the extension period falling in 2024 and 2025; and the hire rate for the Methane Princess will be reduced by 37% from 2024. The exercise of these options could have a material adverse effect on GMLP’s results of operations and cash flows.

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In July 2018, GMLP completed an acquisition of 50% of the common units in Hilli LLC (as defined here), the disponent owner of Hilli Corp. (as defined herein), the owner of the Hilli. The acquired interest in Hilli LLC represents the equivalent of 50% of the two liquefaction trains, out of a total of four, that have been contracted to Perenco Cameroon SA (“Perenco”) and Société Nationale Des Hydrocarbures (“SNH” and, together with Perenco, the “Customer”) pursuant to a Liquefaction Tolling Agreement (“LTA”) with an 8 year term. The acquired interest is not exposed to the oil linked pricing elements of the tolling fee under the LTA. However, it exposes us to risks that GMLP may:

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fail to realize anticipated benefits through cash distributions from Hilli LLC;

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fail to obtain the benefits of the LTA if the Customer exercises certain rights to terminate the charter upon the occurrence of specified events of default;

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fail to obtain the benefits of the LTA if the Customer fails to make payments under the LTA because of its financial inability, disagreements with us or otherwise;

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incur or assume unanticipated liabilities, losses or costs;

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be required to pay damages to the Customer or suffer a reduction in the tolling fee in the event that the Hilli fails to perform to certain specifications;

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incur other significant charges, such as asset devaluation or restructuring charges; or

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be unable to re-charter the FLNG on another long-term charter at the end of the LTA.

Due to the sophisticated technology utilized by the Hilli, operations are subject to risks that could negatively affect GMLP’s business and financial condition.

FLNG vessels are complex and their operations are technically challenging and subject to mechanical risks and problems. Unforeseen operational problems with the Hilli may lead to Hilli LLC experiencing a loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm GMLP’s business and financial condition.

GMLP guarantees 50% of Hilli Corp’s indebtedness under the Hilli Facility.

Hilli Corp, a wholly owned subsidiary of Hilli LLC, 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 Facility”). The Hilli Facility provided for post-construction financing for the Hilli in the amount of $960 million.

In connection with the closing of the Hilli Acquisition, GMLP agreed to provide a several guarantee (the “GMLP Guarantee”) of 50% of the obligations of Hilli Corp under the Hilli Facility pursuant to a Deed of Amendment, Restatement and Accession relating to a guarantee between GLNG, Fortune and GMLP dated July 12, 2018. In the event that Hilli Corp fails to meet its payment obligations under the Hilli Facility or fails to comply with certain other covenants contained therein, GMLP may be required to make payments to Fortune under the GMLP Guarantee, and such payments may be substantial. The Hilli Facility and the GMLP Guarantee contain certain financial restrictions and other covenants that may restrict GMLP’s business and financing activities.

GMLP may experience operational problems with its vessels that reduce revenue and increase costs.

FSRUs and LNG carriers are complex and their operations are technically challenging. Marine LNG operations are subject to mechanical risks and problems. GMLP’s operating expenses depend on a variety of factors including crew costs, provisions, deck and engine stores and spares, lubricating oil, insurance, maintenance and repairs and shipyard costs, many of which are beyond its control such as the overall economic impacts caused by the global COVID-19 outbreak and affect the entire shipping industry. Factors such as increased cost of qualified and experienced seafaring crew and changes in regulatory requirements could also increase operating expenditures. Future increases to operational costs are likely to occur. If costs rise, they could materially and adversely affect GMLP’s results of operations. In addition, operational problems may lead to loss of revenue or higher than anticipated operating expenses or require additional capital expenditures. Any of these results could harm GMLP’s business, financial condition and results of operations.

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GMLP may be unable to obtain, maintain, and/or renew permits necessary for its operations or experience delays in obtaining such permits, which could have a material effect on its operations.

The design, construction and operation of FSRUs, FLNGs and LNG carriers and interconnecting pipelines require, and are subject to the terms of governmental approvals and permits. The permitting rules, and the interpretations of those rules, are complex, change frequently and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult or impractical, and may increase the length of time it takes to receive regulatory approval for offshore LNG operations. In the future, the relevant regulatory authorities may take actions to restrict or prohibit the access of FSRUs or LNG carriers to various ports or adopt new rules and regulations applicable to FSRUs and LNG carriers that will increase the time needed or affect GMLP’s ability to obtain necessary environmental permits.

A shortage of qualified officers and crew, including due to disruption caused by the outbreak of pandemic diseases, such as COVID-19, could have an adverse effect on GMLP’s business and financial condition.

FSRUs, FLNGs and LNG carriers require technically skilled officers and crews with specialized training. As the worldwide FSRU, FLNG and LNG carrier fleet has grown, the demand for technically skilled officers and crews has increased, which could lead to a shortage of such personnel. Increases in GMLP’s historical vessel operating expenses have been attributable primarily to the rising costs of recruiting and retaining officers for its fleet. If GMLP’s vessel managers are unable to employ technically skilled staff and crew, they will not be able to adequately staff its vessels. A material decrease in the supply of technically skilled officers or an inability of GLNG or its vessel managers to attract and retain such qualified officers could impair its ability to operate or increase the cost of crewing its vessels, which would materially adversely affect GMLP’s business, financial condition and results of operations.

In addition, the Golar Winter is employed by Petrobras in Brazil. As a result, GMLP is required to hire a certain portion of Brazilian personnel to crew this vessel in accordance with Brazilian law. Also, the NR Satu is employed by PT Nusantara Regas, in Indonesia. As a result, GMLP is required to hire a certain portion of Indonesian personnel to crew the NR Satu in accordance with Indonesian law. Any inability to attract and retain qualified Brazilian and Indonesian crew members could adversely affect its business, results of operations and financial condition.

Furthermore, should there be an outbreak of COVID-19 on board one of GMLP’s vessels, adequate crewing may not be available to fulfill the obligations under its contracts. Due to COVID-19, GMLP could face (i) difficulty in finding healthy qualified replacement officers and crew; (ii) local or international transport or quarantine restrictions limiting the ability to transfer infected crew members off the vessel or bring new crew on board, and (iii) restrictions in availability of supplies needed on board due to disruptions to third-party suppliers or transportation alternatives. Any inability GLNG or its affiliates experiences in the future to attract, hire, train and retain a sufficient number of qualified employees could impair GMLP’s ability to manage, maintain and grow its business.

Due to the locations in which GMLP operate, GMLP is subject to political and security risks.

GMLP’s operations may be affected by economic, political and governmental conditions in the countries where GMLP is engaged in business or where its vessels are registered. Any disruption caused by these factors could harm its business. In particular:

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GMLP derives a substantial portion of its revenues from shipping LNG from politically unstable regions, particularly the Arabian Gulf, Brazil, Indonesia and West Africa. Past political conflicts in certain of these regions have included attacks on vessels, mining of waterways and other efforts to disrupt shipping in the area. In addition to acts of terrorism, vessels trading in these and other regions have also been subject, in limited instances, to piracy. Future hostilities or other political instability in the regions in which GMLP operates or may operate could have a material adverse effect on the growth of its business, results of operations and financial condition and its ability to make cash distributions. In addition, tariffs, trade embargoes and other economic sanctions by the United States or other countries against countries in the Middle East, Southeast Asia, Africa or elsewhere as a result of terrorist attacks, hostilities or otherwise may limit trading activities with those countries, which could also harm GMLP’s business and ability to make cash distributions.

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The operations of Hilli Corp in Cameroon under the LTA are subject to higher political and security risks than operations in other areas of the world. Recently, Cameroon has experienced instability in its socio-political environment. Any extreme levels of political instability resulting in changes of governments, internal conflict, unrest and violence, especially from terrorist organizations prevalent in the region, such as Boko Haram, could lead to economic disruptions and shutdowns in industrial activities. In addition, corruption and bribery are a serious concern in the region. The operations of Hilli Corp in Cameroon are subject to these risks, which could materially adversely affect GMLP’s revenues, its ability to perform under the LTA and its financial condition.

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In addition, Hilli Corp maintains insurance coverage for only a portion of the risks incidental to doing business in Cameroon. There also may be certain risks covered by insurance where the policy does not reimburse Hilli Corp for all of the costs related to a loss. For example, any claims covered by insurance will be subject to deductibles, which may be significant. In the event that Hilli Corp incurs business interruption losses with respect to one or more incidents, they could have a material adverse effect on GMLP’s results of operations.

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Vessel values may fluctuate substantially and, if these values are lower at a time when GMLP is attempting to dispose of vessels, GMLP may incur a loss.

Vessel values can fluctuate substantially over time due to a number of different factors, including:

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prevailing economic conditions in the natural gas and energy markets;

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a substantial or extended decline in demand for LNG;

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increases in the supply of vessel capacity without a commensurate increase in demand;

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the size and age of a vessel; and

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the cost of retrofitting or modifying existing vessels, as a result of technological advances in vessel design or equipment, changes in applicable environmental or other regulations or standards, customer requirements or otherwise.

As GMLP’s vessels age, the expenses associated with maintaining and operating them are expected to increase, which could have an adverse effect on its business and operations if GMLP do not maintain sufficient cash reserves for maintenance and replacement capital expenditures. Moreover, the cost of a replacement vessel would be significant.

During the period a vessel is subject to a charter, GMLP will not be permitted to sell it to take advantage of increases in vessel values without the charterers’ consent. If a charter terminates, GMLP may be unable to re-deploy the affected vessels at attractive rates and, rather than continue to incur costs to maintain and finance them, GMLP may seek to dispose of them. When vessel values are low, GMLP may not be able to dispose of vessels at a reasonable price when GMLP wish to sell vessels, and conversely, when vessel values are elevated, GMLP may not be able to acquire additional vessels at attractive prices when GMLP wish to acquire additional vessels, which could adversely affect GMLP’s business, results of operations, cash flow, financial condition and ability to make distributions to unitholders.

The carrying values of GMLP’s vessels may not represent their fair market value at any point in time because the market prices of secondhand vessels tend to fluctuate with changes in charter rates and the cost of new build vessels. GMLP’s vessels are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Although GMLP did not recognize an impairment charge on any of its vessels for the year ended December 31, 2020, GMLP cannot assure you that GMLP will not recognize impairment losses on its vessels in future years. Any impairment charges incurred as a result of declines in charter rates could negatively affect GMLP’s business, financial condition, operating results or the trading price of GMLP’s common and preferred units.

GMLP vessels may call on ports located in countries that are subject to restrictions imposed by the U.S. or other governments, which could adversely affect its business.

Although no vessels operated by GMLP have called on ports located in countries subject to comprehensive sanctions and embargoes imposed by the U.S. government or countries identified by the U.S. government as state sponsors of terrorism, in the future GMLP’s vessels may call on ports in these countries from time to time on its charterers’ instructions. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time.

Although GMLP believes that it has been in compliance with all applicable sanctions and embargo laws and regulations, and intends to maintain such compliance, there can be no assurance that GMLP will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact GMLP’s ability to access U.S. capital markets and conduct its business. In addition, certain financial institutions may have policies against lending or extending credit to companies that have contracts with U.S. embargoed countries or countries identified by the U.S. government as state sponsors of terrorism. Moreover, GMLP charterers may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve GMLP or its vessels, and those violations could in turn negatively affect GMLP’s reputation. In addition, GMLP’s reputation may be adversely affected if it engages in certain other activities, such as entering into charters with individuals or entities in countries subject to U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.

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Maritime claimants could arrest GMLP’s vessels, which could interrupt its cash flow.

If GMLP is in default on certain kinds of obligations, such as those to its lenders, crew members, suppliers of goods and services to its vessels or shippers of cargo, these parties may be entitled to a maritime lien against one or more of GMLP’s vessels. In many jurisdictions, a maritime lien holder may enforce its lien by arresting a vessel through foreclosure proceedings. In a few jurisdictions, claimants could try to assert “sister ship” liability against one vessel in GMLP’s fleet for claims relating to another of its vessels. The arrest or attachment of one or more of GMLP’s vessels could interrupt its cash flow and require it to pay to have the arrest lifted. Under some of GMLP’s present charters, if the vessel is arrested or detained (for as few as 14 days in the case of one of our charters) as a result of a claim against it, GMLP may be in default of its charter and the charterer may terminate the charter. This would negatively impact GMLP’s revenues and reduce its cash available for distribution to unitholders.

Risks Related to Ownership of Our Class A Common Stock

The Proposed Mergers may not occur, and if they do, they may not be accretive and may cause dilution to our earnings per share, which may negatively affect the market price of our common stock.

Although we currently anticipate that the Proposed Mergers will occur and will be accretive to earnings per share (on an as adjusted earnings basis that is not pursuant to GAAP) from and after the Proposed Mergers, this expectation is based on assumptions about our, Hygo’s and GMLP’s business and preliminary estimates, which may change materially. As a result, should the Proposed Mergers occur, certain other amounts to be paid in connection with the Proposed Mergers may cause dilution to our earnings per share or decrease or delay the expected accretive effect of the Proposed Mergers and cause a decrease in the market price of our common stock. The Proposed Mergers may not occur as a result. See “—Risks Related to the Proposed Mergers.” In addition, we could also encounter additional transaction-related costs or other factors such as the failure to realize all of the benefits anticipated in the Proposed Mergers, including cost and revenue synergies. All of these factors could cause dilution to our earnings per share or decrease or delay the expected accretive effect of the Proposed Mergers and cause a decrease in the market price of our common stock.

The market price and trading volume of our Class A common stock may be volatile, which could result in rapid and substantial losses for our stockholders.

The market price of our Class A common stock may be highly volatile and could be subject to wide fluctuations. In addition, the trading volume in our Class A common stock may fluctuate and cause significant price variations to occur. If the market price of our Class A common stock declines significantly, you may be unable to resell your shares at or above your purchase price, if at all. The market price of our Class A common stock may fluctuate or decline significantly in the future. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our Class A common stock include:

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a shift in our investor base;

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our quarterly or annual earnings, or those of other comparable companies;

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actual or anticipated fluctuations in our operating results;

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changes in accounting standards, policies, guidance, interpretations or principles;

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announcements by us or our competitors of significant investments, acquisitions or dispositions;

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the failure of securities analysts to cover our Class A common stock;

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changes in earnings estimates by securities analysts or our ability to meet those estimates;

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the operating and share price performance of other comparable companies;

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overall market fluctuations;

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general economic conditions; and

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developments in the markets and market sectors in which we participate.

Stock markets in the United States have experienced extreme price and volume fluctuations. Market fluctuations, as well as general political and economic conditions such as acts of terrorism, prolonged economic uncertainty, a recession or interest rate or currency rate fluctuations, could adversely affect the market price of our Class A common stock.

Furthermore, the market price of our common stock may fluctuate significantly following consummation of the Proposed Mergers if, among other things, the combined company is unable to achieve the expected growth in earnings, or if the operational cost savings estimates in connection with the integration of our, Hygo’s and GMLP’s businesses are not realized, or if the transaction costs relating to the Proposed Mergers are greater than expected, or if the financing relating to the transaction is on unfavorable terms. The market price also may decline if the combined company does not achieve the perceived benefits of the Proposed Mergers as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Proposed Mergers on the combined company’s financial position, results of operations or cash flows is not consistent with the expectations of financial or industry analysts. In addition, the results of operations of the combined company and the market price of our common stock after the completion of the Proposed Mergers may be affected by factors different from those currently affecting the independent results of operations of each of our, Hygo’s and GMLP’s and business.

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We are a “controlled company” within the meaning of Nasdaq rules and, as a result, qualify for and intend to rely on exemptions from certain corporate governance requirements.

Affiliates of certain entities controlled by Wesley R. Edens and Randal A. Nardone (“Founder Entities”) hold a majority of the voting power of our stock. In addition, pursuant to the Shareholders’ Agreement, dated as of February 4, 2019, by and among the Company and the respective parties thereto (the “Shareholders’ Agreement”), the Founder Entities currently have the right to nominate a majority of the members of our Board of Directors. Furthermore, the Shareholders’ Agreement provides that the parties thereto will use their respective reasonable efforts (including voting or causing to be voted all of the Company’s voting shares beneficially owned by each) to cause to be elected to the Board, and to cause to continue to be in office the director nominees selected by the Founder Entities. Affiliates of Fortress Investment Group LLC and NFE SMRS Holdings LLC are parties to the Shareholders’ Agreement and as of March 15, 2021 collectively hold approximately 27% of the voting power of our stock. As a result, we are a controlled company within the meaning of the Nasdaq corporate governance standards. Under Nasdaq rules, a company of which more than 50% of the voting power for the election of directors is held by an individual, a group or another company is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:

•

a majority of the board of directors consist of independent directors as defined under the rules of Nasdaq;

•

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

•

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements will not apply to us as long as we remain a controlled company. A controlled company does not need its board of directors to have a majority of independent directors or to form independent compensation and nominating and governance committees. We intend to utilize some or all of these exemptions. Accordingly, our corporate governance may not afford the same protections as companies that are subject to all of the corporate governance requirements of Nasdaq.

A small number of our original investors have the ability to direct the voting of a majority of our stock, and their interests may conflict with those of our other stockholders.

As of March 15, 2021, affiliates of the Founder Entities own an aggregate of approximately 98,824,301 shares of Class A common stock, representing 56.2% of our voting power. As of March 15, 2021, Wesley R. Edens and Randal A. Nardone directly or indirectly own 72,627,775 shares and 26,196,526 shares, respectively, of our Class A common stock, representing 41.3% and 14.9% of the voting power of the Class A common stock, respectively. The beneficial ownership of greater than 50% of our voting stock means affiliates of the Founder Entities are able to control matters requiring stockholder approval, including the election of directors, changes to our organizational documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or group of holders of our Class A common stock will be able to affect the way we are managed or the direction of our business. The interests of the affiliates of the Founder Entities with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other stockholders, including holders of the Class A common stock.

Given this concentrated ownership, the affiliates of the Founder Entities would have to approve any potential acquisition of us. The existence of a significant stockholder may have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company. Moreover, the concentration of stock ownership with affiliates of the Founder Entities may adversely affect the trading price of our securities, including our Class A common stock, to the extent investors perceive a disadvantage in owning securities of a company with a significant stockholder.

Furthermore, in connection with the IPO, we entered into a shareholders’ agreement (the “Shareholders’ Agreement”) with New Fortress Energy Holdings and its affiliates, and in connection with the Exchange Transactions (as defined herein), New Fortress Energy Holdings assigned, pursuant to the terms of the Shareholders’ Agreement, to the Founder Entities, New Fortress Energy Holdings’ right to designate a certain number of individuals to be nominated for election to our board of directors so long as its assignees collectively beneficially own at least 5% of the outstanding Class A common stock. The Shareholders’ Agreement provides that the parties to the Shareholders’ Agreement (including certain former members of New Fortress Energy Holdings) shall vote their stock in favor of such nominees. In addition our Certificate of Incorporation provides the Founder Entities the right to approve certain material transactions so long as the Founder Entities and their affiliates collectively, directly or indirectly, own at least 30% of the outstanding Class A common stock.

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Our Certificate of Incorporation and By-Laws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock and could deprive our investors of the opportunity to receive a premium for their Class A common stock.

Our Certificate of Incorporation and By-Laws authorize our board of directors to issue preferred stock without stockholder approval in one or more series, designate the number of stock constituting any series, and fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights, rights and terms of redemption, redemption price or prices and liquidation preferences of such series. If our board of directors elects to issue preferred stock, it could be more difficult for a third-party to acquire us. In addition, some provisions of our Certificate of Incorporation and By-Laws could make it more difficult for a third-party to acquire control of us, even if the change of control would be beneficial to our securityholders. These provisions include:

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dividing our board of directors into three classes of directors, with each class serving staggered three-year terms;

•

providing that all vacancies, including newly created directorships, may, except as otherwise required by law, or, if applicable, the rights of holders of a series of preferred stock, only be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

•

permitting special meetings of our stockholders to be called only by (i) the chairman of our board of directors, (ii) a majority of our board of directors, or (iii) a committee of our board of directors that has been duly designated by the board of directors and whose powers include the authority to call such meetings;

•

prohibiting cumulative voting in the election of directors;

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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of the stockholders; and

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providing that the board of directors is expressly authorized to adopt, or to alter or repeal our certain provisions of our organizational documents to the extent permitted by law.

Additionally, our Certificate of Incorporation provides that we have opted out of Section 203 of the Delaware General Corporation Law. However, our Certificate of Incorporation includes a similar provision, which, subject to certain exceptions, prohibits us from engaging in a business combination with an “interested stockholder,” unless the business combination is approved in a prescribed manner. Subject to certain exceptions, an “interested stockholder” means any person who, together with that person’s affiliates and associates, owns 15% or more of our outstanding voting stock or an affiliate or associate of ours who owned 15% or more of our outstanding voting stock at any time within the previous three years, but shall not include any person who acquired such stock from the Founder Entities or NFE SMRS Holdings LLC (except in the context of a public offering) or any person whose ownership of stock in excess of 15% of our outstanding voting stock is the result of any action taken solely by us. Our Certificate of Incorporation provides that the Founder Entities and NFE SMRS Holdings LLC and any of their respective direct or indirect transferees, and any group as to which such persons are a party, do not constitute “interested stockholders” for purposes of this provision.

Our Certificate of Incorporation and By-Laws designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Certificate of Incorporation and By-Laws provide that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is, to the fullest extent permitted by applicable law, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any of our directors, officers or employees arising pursuant to any provision of our organizational documents, the Delaware Limited Liability Company Act or the DGCL, as applicable, or (iv) any action asserting a claim against us or any of our directors, officers or employees that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in our stock will be deemed to have notice of, and consented to, the provisions described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it considers more likely to be favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our organizational documents inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, results of operations or prospects.

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The declaration and payment of dividends to holders of our Class A common stock will be at the discretion of our board of directors in accordance with applicable law after taking into account various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deem relevant. There can be no assurance that we will continue to pay dividends in amounts or on a basis consistent with prior distributions to our investors, if at all. Because we are a holding company and have no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries and our ability to receive distributions from our subsidiaries may be limited by the financing agreements to which they are subject.

The incurrence or issuance of debt which ranks senior to our Class A common stock upon our liquidation, including any debt issued in connection with the financing of the Proposed Mergers and future issuances of equity or equity-related securities, which would dilute the holdings of our existing Class A common stockholders and may be senior to our Class A common stock for the purposes of making distributions, periodically or upon liquidation, may negatively affect the market price of our Class A common stock.

We have incurred and may in the future incur or issue debt, including any debt issued in connection with the financing of the Proposed Mergers, or issue equity or equity-related securities to finance our operations, acquisitions or investments. Upon our liquidation, lenders and holders of our debt and holders of our preferred stock (if any) would receive a distribution of our available assets before Class A common stockholders. Any future incurrence or issuance of debt would increase our interest cost and could adversely affect our results of operations and cash flows. We are not required to offer any additional equity securities to existing Class A common stockholders on a preemptive basis. Therefore, additional issuances of Class A common stock, directly or through convertible or exchangeable securities (including limited partnership interests in our operating partnership), warrants or options, will dilute the holdings of our existing Class A common stockholders and such issuances, or the perception of such issuances, may reduce the market price of our Class A common stock. Any preferred stock issued by us would likely have a preference on distribution payments, periodically or upon liquidation, which could eliminate or otherwise limit our ability to make distributions to Class A common stockholders. Because our decision to incur or issue debt or issue equity or equity-related securities in the future will depend on market conditions and other factors beyond our control, we cannot predict or estimate the amount, timing, nature or success of our future capital raising efforts. Thus, Class A common stockholders bear the risk that our future incurrence or issuance of debt or issuance of equity or equity-related securities will adversely affect the market price of our Class A common stock.

We may issue preferred stock, the terms of which could adversely affect the voting power or value of our Class A common stock.

Our Certificate of Incorporation and By-Laws authorize us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock in respect of dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the Class A common stock.

Sales or issuances of our Class A common stock could adversely affect the market price of our Class A common stock.

Sales of substantial amounts of our Class A common stock in the public market, or the perception that such sales might occur, could adversely affect the market price of our Class A common stock. The issuance of our Class A common stock in connection with property, portfolio or business acquisitions or the exercise of outstanding options or otherwise could also have an adverse effect on the market price of our Class A common stock.

An active, liquid and orderly trading market for our Class A common stock may not be maintained and the price of our Class A common stock may fluctuate significantly.

Prior to January 2019, there was no public market for our Class A common stock. An active, liquid and orderly trading market for our Class A common stock may not be maintained. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock.

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We recently ceased to be an emerging growth company, and now are required to comply with certain heightened reporting requirements, including those relating to auditing standards and disclosure about our executive compensation.

The Jumpstart Our Business Startups Act of 2012, or “JOBS Act”, contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to auditing standards and compensation disclosure. Prior to September 2, 2020, we were classified as an emerging growth company. As an emerging growth company, we were not required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act and (ii) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) provide certain disclosures regarding executive compensation required of larger public companies or (iv) hold nonbinding advisory votes on executive compensation. When we were an emerging growth company, we followed the exemptions described above. We also elected to use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards under Section 102(b)(2) of the JOBS Act. This election allowed us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result, our financial statements may not have been comparable to companies that comply with public company effective dates, and our stockholders and potential investors may have difficulty in analyzing our historical operating results if comparing us to such companies. In addition, because we relied on exemptions available to emerging growth companies, our historical public filings contained less information about our executive compensation and internal control over financial reporting than issuers that are not emerging growth companies.

We expect to incur additional costs associated with the heightened reporting requirements described above, including the requirement to provide auditor’s attestation report on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, as well as additional audit costs resulting from PCAOB requirements. In addition, our auditors may identify control deficiencies of varying degrees of severity, and we may incur significant costs to remediate those deficiencies or otherwise improve our internal controls. As a public company, we are required to report any control deficiencies that constitute a “material weakness” in our internal control over financial reporting, and doing so could impair our ability to raise capital and otherwise adversely affect the value of our securities.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our Class A common stock.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our Class A common stock.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with stock listed on Nasdaq, we are and will be subject to an extensive body of regulations that did not apply to us previously, including certain provisions of the Sarbanes-Oxley Act, the Dodd-Frank Act, regulations of the SEC and Nasdaq requirements. Compliance with these rules and regulations increase our legal, accounting, compliance and other expenses that we did not incur prior to the IPO and has made some activities more time-consuming and costly. For example, as a result of becoming a public company, we added independent directors and created additional board committees. We entered into an administrative services agreement with FIG LLC, an affiliate of Fortress Investment Group (which currently employs Messrs. Edens, our chief executive officer and chairman of our Board of Directors, and Nardone, one of our Directors), in connection with the IPO, pursuant to which FIG LLC provides us with certain back-office services and charges us for selling, general and administrative expenses incurred to provide these services. FIG LLC will also continue to provide compliance services for the foreseeable future. In addition, we may incur additional costs associated with our public company reporting requirements and maintaining directors’ and officers’ liability insurance. It is possible that our actual incremental costs of being a publicly traded company will be higher than we currently estimate, and the incremental costs may have a material adverse effect on our business, prospects, financial condition, results of operations and cash flows.

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If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our Class A common stock or if our operating results do not meet their expectations, our share price could decline.

The trading market for our Class A common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose viability in the financial markets, which in turn could cause our share price or trading volume to decline.

We may fail to realize the anticipated benefits of the Exchange Transactions and the Conversion or those benefits may take longer to realize than expected or may not offset the costs of the Exchange Transactions and the Conversion, which could have an adverse impact on the trading price of our Class A common stock.

We expect the Exchange Transactions and the Conversion will confer several significant benefits to us. Most notably, we expect that the Exchange Transactions will significantly reduce our future tax distribution obligations to the members of NFI, which will enable us to instead invest those funds to develop projects that we expect will increase our returns for all stockholders, enhance our liquidity, improve our credit profile and potentially lower our cost of capital.

We may fail to realize the anticipated benefits of the Exchange Transactions and the Conversion or those benefits may take longer to realize than we expect. Moreover, there can be no assurance that the anticipated benefits of the Exchange Transactions and the Conversion will offset their costs. Our failure to achieve the anticipated benefits of the Exchange Transactions and the Conversion at all or in a timely manner, or a failure of any benefits realized to offset its costs, could have an adverse impact on the trading price of our Class A common stock.

Item 1B.

Unresolved Staff Comments.

None.

Item 3.

Legal Proceedings.

We are not currently a party to any material legal proceedings. In the ordinary course of business, various legal and regulatory claims and proceedings may be pending or threatened against us. If we become a party to proceedings in the future, we may be unable to predict with certainty the ultimate outcome of such claims and proceedings.

Item 4.

Mine Safety Disclosures.

Not applicable.

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PART II

Item 5.

Market for the Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities.

Market Information

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “NFE.” On March 15, 2021, there were eight holders of record of our Class A common stock. This number does not include shareholders whose shares are held for them in “street name” meaning that such shares are held for their accounts by a broker or other nominee. The actual number of beneficial shareholders is greater than the number of holders of record.

Dividends

We declared dividends of $0.10 per share in August and October 2020, totaling $33,742 in dividend payments during the year ended December 31, 2020. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations and financial condition, capital requirements, business prospects, statutory and contractual restrictions on our ability to pay dividends, including restrictions contained in our debt agreements, and other factors our board of directors may deem relevant.

Securities Authorized for Issuance Under Equity Compensation Plans

The information required by this Item is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholders and is incorporated herein by reference.

Share Performance Graph

The following graph compares the cumulative total return to shareholders on our Class A common stock relative to the S&P 500, Alerian Midstream Index (“AMNA”) and Vanguard Energy ETF (“VDE”), including reinvestment of dividends. The graph assumes that on January 31, 2019, the date our Class A shares began trading on the NASDAQ, $100 was invested in our Class A shares and in each index based on the closing market price, and that all dividends were reinvested. The returns shown are based on historical results and are not intended to suggest future performance.

The following Performance Graph and related information is being furnished and shall not be deemed “soliciting material” or “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent we specifically incorporate it by reference into such filing.

Cumulative Total Return Percentage
Company / Index	January 31, 2019⁽¹⁾	March ^2019(2)	June ^2019(2)	Sepember ^2019(2)	December ^2019(2)	March ^2020(2)	June ^2020(2)	Sepember ^2020(2)	December ^2020(2)
NFE	100	(10.6)	(10.4)	37.9	19.9	(25.1)	(0.8)	237.9	312.4
S&P 500	100	4.8	8.8	10.1	19.5	(4.4)	14.7	24.4	38.9
Alerian Midstream Index (“AMNA”)	100	2.5	0.6	(6.4)	(12.3)	(63.3)	(46.5)	(56.6)	(44.2)
Vanguard Energy ETF (“VDE”)	100	4.5	0.2	(7.2)	(2.2)	(53.5)	(38.0)	(49.7)	(34.5)

(1)	Date of the IPO

(2)	Last trading day of the month

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Use of Proceeds from Registered Securities

On February 4, 2019, we completed the IPO of 20,000,000 Class A shares pursuant to our registration statement on Form S-1 (File No. 333-228339) (the “Registration Statement”) declared effective by the SEC on January 30, 2019. In connection with the IPO, Morgan Stanley & Co. LLC, Barclays Capital Inc., Citigroup Global Markets Inc. and Credit Suisse Securities (USA) LLC acted as representatives of the underwriters; Evercore Group L.L.C. and Allen & Company LLC acted as joint book-running managers; and JMP Securities LLC and Stifel, Nicolaus & Company Incorporated acted as co-managers. The gross proceeds of the IPO, based on a public offering price of $14.00 per Class A share, were $280.0 million, which resulted in net proceeds to us of $257.0 million, after deducting underwriting discounts and commissions and transaction costs. In addition, on March 1, 2019, the underwriters exercised their option to purchase an additional 837,272 Class A shares at the initial offering price of $14.00 per share, less underwriting discounts, which resulted in $11.0 million in additional net proceeds after deducting underwriting discounts and commissions, such that there were 20,837,272 outstanding Class A shares. We contributed the net proceeds of the IPO to NFI in exchange for NFI’s issuance to us of 20,837,272 NFI LLC Units. NFI used the net proceeds in connection with the construction of our Facilities, as well as for working capital and general corporate purposes, including the development of future projects. No fees or expenses were paid, directly or indirectly, to any officer, director, 10% unitholder or other affiliate.

In December 2020, NFE issued 5,882,352 shares of Class A common stock and received proceeds of $290.8 million, net of $1.2 million in issuance costs. The use of these proceeds will be for general corporate purposes.

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Item 6.

Selected Financial Data.

The following table presents our selected historical consolidated financial and operating data. NFE was formed on August 6, 2018 and did not have historical financial results. The selected historical financial data as of December 31, 2018, 2017 and 2016 and for the years ended December 31, 2018, 2017 and 2016, prior to the IPO, was derived from the audited historical consolidated financial statements of New Fortress Energy Holdings, our predecessor for financial reporting purposes. Due to the change in organization structure as a result of reorganization transactions completed at the time of our IPO in 2019, the net loss per share and weighted average number of shares outstanding are not presented for the years ended December 31, 2018, 2017 and 2016.

You should read the information set forth below together with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included elsewhere in this Annual Report. The historical financial results are not necessarily indicative of results to be expected for any future periods.

	Year Ended December 31,
	2020			2019			2018			2017			2016
	(In thousands, except share and per share amounts)
Statements of Operations Data:

Revenues
Operating revenue	$	318,311		$	145,500		$	96,906		$	82,104		$	18,615
Other revenue		133,339			43,625			15,395			15,158			2,780
Total revenues		451,650			189,125			112,301			97,262			21,395

Operating expenses
Cost of sales		278,767			183,359			95,742			78,692			22,747
Operations and maintenance		47,581			26,899			9,589			7,456			5,205
Selling, general and administrative		124,170			152,922			62,137			33,343			18,160
Contract termination charges and loss on mitigation sales		124,114			5,280			-			-			-
Depreciation and amortization		32,376			7,940			3,321			2,761			2,341
Total operating expenses		607,008			376,400			170,789			122,252			48,453
Operating loss		(155,358	)		(187,275	)		(58,488	)		(24,990	)		(27,058	)
Interest expense		65,723			19,412			11,248			6,456			5,105
Other expense (income), net		5,005			(2,807	)		(784	)		(301	)		(53	)
Loss on extinguishment of debt, net		33,062			-			9,568			-			1,177
Loss before taxes		(259,148	)		(203,880	)		(78,520	)		(31,145	)		(33,287	)
Tax expense (benefit)		4,817			439			(338	)		526			(361	)
Net loss		(263,965	)		(204,319	)		(78,182	)		(31,671	)		(32,926	)
Net loss attributable to non-controlling interest		81,818			170,510			106			-			-
Net loss atrributable to stockholders	$	(182,147	)	$	(33,809	)	$	(78,076	)	$	(31,671	)	$	(32,926	)

Net loss per share - basic and diluted	$	(1.71	)	$	(1.62	)
Weighted average number of shares outstanding - basic and diluted		106,654,918			20,862,555

	As of December 31,
	2020		2019		2018		2017		2016
Balance Sheet Data (at period end):
Property, plant and equipment, net	$	614,206	$	192,222	$	94,040	$	69,350	$	70,633
Construction in progress		234,037		466,587		254,700		35,413		4,668
Total assets		1,908,091		1,123,814		699,402		381,190		389,054
Long-term debt (includes current portion)		1,239,561		619,057		272,192		75,253		80,385
Total liabilities		1,533,005		736,490		416,755		102,280		99,684

	Year Ended December 31,
	2020			2019			2018			2017			2016
Statements of Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	(125,566	)	$	(234,261	)	$	(93,227	)	$	(54,892	)	$	(43,493	)
Investing activities		(157,631	)		(376,164	)		(184,455	)		(29,858	)		(98,325	)
Financing activities		819,498			602,607			260,204			13,960			275,936

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Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Certain information contained in this discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors. You should read “Part 1, Item 1A. Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Annual Report on Form 10-K (“Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

The comparison of the years ended December 31, 2019 and 2018 can be found in our Annual Report on Form 10‑K for the year ended December 31, 2019 located within “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The following information should be read in conjunction with our audited consolidated financial statements and accompanying notes included elsewhere in this Annual Report. Our financial statements have been prepared in accordance with GAAP. This information is intended to provide investors with an understanding of our past performance and our current financial condition and is not necessarily indicative of our future performance. Please refer to “—Factors Impacting Comparability of Our Financial Results” for further discussion. Unless otherwise indicated, dollar amounts are presented in thousands.

Unless the context otherwise requires, references to “Company,” “NFE,” “we,” “our,” “us” or like terms refer to (i) prior to our conversion from a limited liability company to a corporation, New Fortress Energy LLC and its subsidiaries and (ii) following the conversion from a limited liability company to a corporation, New Fortress Energy Inc. and its subsidiaries. When used in a historical context that is prior to the completion of NFE’s initial public offering (“IPO”), “Company,” “we,” “our,” “us” or like terms refer to New Fortress Energy Holdings LLC, a Delaware limited liability company (“New Fortress Energy Holdings”), our predecessor for financial reporting purposes.

Overview

As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. We currently source LNG from long-term supply agreements with third party suppliers and from our own liquefaction facility in Miami, Florida. We expect that control of our vertical supply chain, from procurement to delivery of LNG, will help to reduce our exposure to future LNG price variations and enable us to supply our existing and future customers with LNG at a price that reinforces our competitive standing in the LNG market. Our strategy is simple: we seek to procure LNG at attractive prices using long-term agreements and through our own production, and we seek to sell natural gas (delivered through LNG infrastructure) or gas-fired power to customers that sign long-term, take-or-pay contracts.

Our Current Operations

Our management team has successfully employed our strategy to secure long-term contracts with significant customers in Jamaica and Puerto Rico, including Jamaica Public Service Company Limited (“JPS”), the sole public utility in Jamaica, South Jamaica Power Company Limited (“SJPC”), an affiliate of JPS, Jamalco, a bauxite mining and alumina production in Jamaica, and the Puerto Rico Electric Power Authority (“PREPA”), each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers.

We currently procure our LNG either by purchasing from a supplier or by manufacturing it in our natural gas liquefaction and storage facility located in Miami-Dade County, Florida (the “Miami Facility”). Our long-term goal is to develop the infrastructure necessary to supply our existing and future customers with LNG produced primarily at our own facilities, including our expanded delivery logistics chain in Northern Pennsylvania (the “Pennsylvania Facility”).

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Montego Bay Facility

Our storage and regasification terminal in Montego Bay, Jamaica (the “Montego Bay Facility”) serves as our supply hub for the north side of Jamaica, providing natural gas to JPS to fuel the 145MW Bogue Power Plant in Montego Bay, Jamaica. Our Montego Bay Facility commenced commercial operations in October 2016 and is capable of processing up to 740,000 gallons of LNG (61,000 MMBtu) per day and features approximately 7,000 cubic meters of onsite storage. The Montego Bay Facility also consists of an ISO loading facility that can transport LNG to numerous on-island industrial users.

Old Harbour Facility

Our marine LNG storage and regasification facility in Old Harbour, Jamaica (the “Old Harbour Facility”) commenced commercial operations in June 2019 and is capable of processing approximately six million gallons of LNG (500,000 MMBtu) per day. The Old Harbour Facility supplies natural gas to the new 190MW Old Harbour power plant (the “Old Harbour Power Plant”) operated by SJPC. The Old Harbour Facility is also supplying natural gas to our dual-fired combined heat and power facility in Clarendon, Jamaica (the “CHP Plant”). The CHP Plant supplies electricity to JPS under a long-term power purchase agreement. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay steam supply agreement. On March 3, 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. In August 2020, we began to deliver gas to Jamalco to utilize in their gas-fired boilers.

San Juan Facility

In July 2020, we finalized the development of the micro-fuel handling facility in the Port of San Juan, Puerto Rico (the “San Juan Facility”). The San Juan Facility is near the San Juan Power Plant and serves as our supply hub for the San Juan Power Plant and other industrial end-user customers in Puerto Rico. We have delivered natural gas used for the commissioning of PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020.

Miami Facility

Our Miami Facility began operations in April 2016. This facility has liquefaction capacity of approximately 100,000 gallons of LNG (8,300 MMBtu) per day and enables us to produce LNG for sales directly to industrial end-users in southern Florida, including Florida East Coast Railway via our train loading facility, and other customers throughout the Caribbean using ISO containers.

Other Development Projects

We are in the process of developing an LNG regasification facility and power plant at the Port of Pichilingue in Baja California Sur, Mexico (the “La Paz Facility”). Initially, the La Paz Facility is expected to supply approximately 270,000 gallons of LNG (22,300 MMBtu) per day under an intercompany GSA for approximately 100 MW of power supplied by gas-fired modular power units that we plan to develop, own and operated, which may be increased to 350,000 gallons (29,000 MMBtu) of LNG per day for up to 135 MW of power. In addition, we were declared the winner of a bid with CFEnergia for the supply of natural gas to power plants located in Punta Prieta and Coromuel for an estimated 250,000 gallons of LNG (20,700 MMBtu) per day and are in the process of finalizing definitive agreements for this supply.

We are also in the process of developing an LNG regasification facility and power plant in Puerto Sandino, Nicaragua (the “Puerto Sandino Facility”). In February 2020, we entered into a 25-year power purchase agreement with Nicaragua’s electricity distribution companies, and we are in the process of constructing an approximately 300 MW natural gas-fired power plant that will consume approximately 700,000 gallons of LNG (57,500 MMBtus) per day.

Recent Developments: Hygo and GMLP Acquisitions

Hygo Acquisition

On January 13, 2021, NFE and Lobos Acquisition Ltd., a Bermuda exempted company and our wholly-owned subsidiary (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (the “Hygo Merger Agreement”) with Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”) and Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), pursuant to which Hygo Merger Sub will merge with and into Hygo (the “Hygo Merger”), with Hygo surviving the Hygo Merger as a wholly owned subsidiary of NFE. As of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.

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The Hygo Merger is expected to close in the first half of 2021, subject to receipt of applicable regulatory approvals and other customary closing conditions.

Upon completion of the acquisition of Hygo, we expect to acquire one operating FSRU terminal in Sergipe, Brazil (the “Sergipe Terminal”) a 50% interest in a 1.5 GW power plant in Sergipe, Brazil (the “Sergipe Power Plant”), as well as two other FSRU terminals in development in Pará, Brazil (the “Barcarena Terminal”) and Santa Catarina, Brazil (the “Santa Catarina Terminal”). In addition, we expect to acquire Hygo’s vessel fleet, which consists of the Golar Nanook, a newbuild FSRU moored and in service at the Sergipe Terminal, and two operating LNG carriers, the Golar Celsius and the Golar Penguin, which may be converted into FSRUs.

GMLP Acquisition

On January 13, 2021, we entered into an Agreement and Plan of Merger (the “GMLP Merger Agreement) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability company and the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and an indirect subsidiary of NFE (“GMLP Merger Sub”), and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales and an indirect subsidiary of NFE (“GP Buyer”), pursuant to which GMLP Merger Sub will merge with and into GMLP, with GMLP surviving the merger as an indirect subsidiary of NFE (the “GMLP Merger”).

Concurrently with the consummation of the GMLP Merger, GP Buyer will purchase from GLNG all of the outstanding membership interests of the General Partner pursuant to a Transfer Agreement dated as of January 13, 2021 for a purchase price of approximately $5 million, which is equivalent to $3.55 per general partner unit of GMLP.

Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel, the Hilli, which receives, liquefies and stores LNG at sea and transfers it to LNG carriers that berth while offshore, each of which are expected to help support our existing facilities and international project pipeline. The majority of the FSRUs in GMLP’s fleet are operating in Brazil, Kuwait, Indonesia, Jamaica and Jordan under time charters. GMLP’s uncontracted vessels are available for short term employment in the spot market.

Suape Development

On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape in the city of Ipojuca, State of Pernambuco, Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A.(“ Pecém”) and Energética Camaçari Muricy II S.A (“Muricy”). These companies collectively hold certain 15-year power purchase agreements totaling 288 MW for the development of the thermoelectric power plants in the State of Bahia, Brazil. We will seek to obtain the necessary approvals from the Agência Nacional de Energia Elétrica (“ANEEL”) and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics in order to develop and plan to construct a 288MW gas-fired power plant and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil.

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COVID-19 Pandemic

We are closely monitoring the impact of the novel coronavirus (“COVID-19”) pandemic on all aspects of our operations and development projects. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis. We have continued to invoice our customers for these fixed minimum volumes even in cases when our customer’s consumption has decreased. We have not changed our payment terms with these customers, and there has not been deterioration in the timing or volume of collections.

Based on the essential nature of the services we provide to support power generation facilities, our development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We remain committed to prioritizing the health and well-being of our employees, customers, suppliers and other partners. We have implemented policies to screen employees, contractors, and vendors for COVID-19 symptoms upon entering our development projects, operations and office facilities. For the year ended December 31, 2020, we have incurred approximately $1.2 million for safety measures introduced into our operations and other responses to the COVID-19 pandemic.

We are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread. We have not experienced significant disruptions in development projects and daily operations during the year ended December 31, 2020 from the COVID-19 pandemic; however, there are important uncertainties including the scope, severity and duration of the pandemic, the actions taken to contain the pandemic or mitigate its impact, and the direct and indirect economic effects of the pandemic and containment measures. We do not currently expect these factors to have a significant impact on our results of operations, liquidity or financial position, or our development budgets or timelines.

Other Matters

We received an order from the Federal Energy Regulatory Commission (“FERC”) on June 18, 2020, which asked us to explain why our San Juan Facility is not subject to FERC’s jurisdiction under section 3 of the Natural Gas Act. While we do not believe that the San Juan Facility is jurisdictional, we provided our reply to FERC on July 20, 2020 and requested that FERC act expeditiously. The matter was raised during a FERC open meeting held on January 19, 2021 but was not resolved, is on the agenda during the FERC open meeting to be held on March 18, 2021, and remains pending. We do not know if or when FERC will respond to our reply, or the outcome of any such response.

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Results of Operations – Year Ended December 31, 2020 compared to Year Ended December 31, 2019 (in thousands)

	Year Ended December 31,
	2020			2019			Change
Revenues
Operating revenue	$	318,311		$	145,500		$	172,811
Other revenue		133,339			43,625			89,714
Total revenues		451,650			189,125			262,525
Operating expenses
Cost of sales		278,767			183,359			95,408
Operations and maintenance		47,581			26,899			20,682
Selling, general and administrative		124,170			152,922			(28,752	)
Contract termination charges and loss on mitigation sales		124,114			5,280			118,834
Depreciation and amortization		32,376			7,940			24,436
Total operating expenses		607,008			376,400			230,608
Operating loss		(155,358	)		(187,275	)		31,917
Interest expense		65,723			19,412			46,311
Other expense (income), net		5,005			(2,807	)		7,812
Loss on extinguishment of debt, net		33,062			-			33,062
Loss before taxes		(259,148	)		(203,880	)		(55,268	)
Tax expense		4,817			439			4,378
Net loss	$	(263,965	)	$	(204,319	)	$	(59,646	)

Revenues

Operating revenue from the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilities for the year ended December 31, 2020 was $318,311 which increased by $172,811 from $145,500 for the year ended December 31, 2019. The increase was primarily driven by volumes sold from the Old Harbour Terminal, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020:

•

For the year ended December 31, 2020, we recognized $189,196 of revenue from volumes sold at the Old Harbour Facility, as compared to $41,229 for the year ended December 31, 2019. Revenue recognized for the year ended December 31, 2020 included $112,334 from sales to the Old Harbour Power Plant and $76,862 from natural gas utilized in the CHP Plant and Jamalco’s boilers. For the year ended December 31, 2020, the volume delivered to the Old Harbour Power Plant was 96.0 million gallons (8.0 TBtu) and the volume utilized in the CHP Plant and Jamalco’s boilers was 96.2 million gallons (7.9 TBtu). For the year ended December 31, 2019, the volume delivered to the Old Harbour Power Plant was 22.2 million gallons (1.9 TBtu).

•

Additional revenue from the delivery of power and steam, which began during March 2020, under our contracts with JPS and Jamalco added $23,062 in revenue for the year ended December 31, 2020.

Operating revenue was also impacted by operations at our Montego Bay Facility, including the following:

•

In connection with the adoption of ASC 842, we no longer identify a lease of the Montego Bay Facility in our gas sale agreement with our customer. Accordingly, interest income associated with the direct financing lease of the Montego Bay Facility is no longer recognized within Other revenue, and all amounts recognized as revenue for activities at the Montego Bay Facility were included in Operating revenue for the year ended December 31, 2020, resulting in an increase of $15,771 to Operating revenue.

•

The increase in Operating revenue is partially offset by a decrease in sales at the Montego Bay Facility. The decrease in sales at the Montego Bay Facility was primarily due to a decrease in sales volume delivered to the Bogue Power Plant. Revenue from sales at the Montego Bay Facility decreased $14,399 to $77,464 for the year ended December 31, 2020 as compared to $91,863 for the year ended December 31, 2019. The delivered volume at the Montego Bay Facility decreased by 16.3 million gallons (1.2 TBtu) from 110.5 million gallons (9.1 TBtu) during the year ended December 31, 2019 to 94.2 million gallons (7.9 TBtu) during the year ended December 31, 2020.

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Other revenue includes revenue from development services, which is recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our power generation facilities, and such services are included within certain long-term contracts to supply these customers with natural gas or outputs from our natural gas-fired facilities. Other revenue increased $89,714 for the year ended December 31, 2020 as compared to the year ended December 31, 2019, and the increases were due to the following:

•

Increase of $113,777 for development services in Puerto Rico for the year ended December 31, 2020, including conversion of the customer’s infrastructure within the San Juan Power Plant and gas used by our customer for testing and commissioning their assets. Development services revenue recognized in the year ended December 31, 2020 included $118,757 for the customer’s use of 129.5 million gallons (10.7 TBtu) of natural gas as part of commissioning their assets.

•

Lower revenue recognized for the infrastructure projects for customers of the CHP Plant. For the year ended December 31, 2020, we recognized $601 for the completion of infrastructure projects for customers of the CHP Plant, as compared to $11,933 for the year ended December 31, 2019.

Cost of sales

Cost of sales includes the procurement of feedgas or LNG, as well as shipping and logistics costs to deliver LNG or natural gas to our facilities, power generation facilities or to our customers. Our LNG and natural gas supply are purchased from third parties or converted in our Miami Facility. Costs to convert natural gas to LNG, including labor, depreciation and other direct costs to operate our Miami Facility are also included in Cost of sales.

Cost of sales for the year ended December 31, 2020 was $278,767 which increased $95,408 from $183,359 for the year ended December 31, 2019.

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 $92,433 for the year ended December 31, 2020 as compared to the year ended December 31, 2019. The increase was primarily attributable to the increase in volumes delivered of approximately 200% compared to the year ended December 31, 2019, partially offset by the decrease in LNG cost. The weighted-average cost of LNG purchased from third parties decreased from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020. The weighted-average cost of our inventory balance as of December 31, 2020 and 2019 was $0.40 per gallon ($4.81 per MMBtu) and $0.64 per gallon ($7.70 per MMBtu), respectively.

Charter costs associated with our expanded fleet increased Cost of sales by $5,763 for the year ended December 31, 2020. The increase was attributable to a full year of charter costs of the Old Harbour Facility in 2020 as well as additional costs associated with our San Juan Facility after the assets were placed in service in the third quarter of 2020.

The increase in Cost of sales was partially offset by a decrease in costs associated with the infrastructure projects for customers of the CHP Plant and conversion of our customer’s infrastructure within the San Juan Power Plant of $11,482 as compared to the year ended December 31, 2019.

Operations and maintenance

Operations and maintenance includes costs of operating our Facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance for the year ended December 31, 2020 was $47,581, which increased $20,682 from $26,899 for the year ended December 31, 2019. The increase is primarily a result of higher logistics costs of $9,727 for the year ended December 31, 2020, primarily associated with the operations of additional charter vessels deployed. Operations and maintenance also increased by $5,425 for the year ended December 31, 2020 for costs of operating the CHP Plant for the period after commencement of commercial operations in March 2020 and by $5,698 for costs of operating the San Juan Facility after our assets were placed in service in the third quarter of 2020.

Selling, general and administrative

Selling, general and administrative includes compensation expenses for our corporate employees, employee travel costs, insurance, professional fees for our advisors and costs associated with development activities for projects that are in initial stages and development is not yet probable.

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Selling, general and administrative for the year ended December 31, 2020, was $124,170 which decreased $28,752 from $152,922 for the year ended December 31, 2019. The decrease was primarily attributable to decreased share-based compensation expense of $32,651, as well as decreases to professional fees of $3,743, as compared to the year ended December 31, 2019. These decreases were partially offset by $8,344 of higher payroll costs associated with increased headcount.

Contract termination charges and loss on mitigation sales

Contract termination charges and loss on mitigation sales for the years ended December 31, 2020 and 2019 was $124,114 and $5,280, respectively. Through 2020, the pricing of LNG in the open market was significantly lower than the pricing in our LNG supply agreement with Centrica. In June 2020, we executed an agreement to terminate our obligation to purchase LNG from Centrica for the remainder of 2020 in exchange for a payment of $105,000, and we recognized this cancellation charge during the second quarter of 2020. We terminated our obligation in the second quarter of 2020 to, among other reasons, take advantage of the low pricing in the open market and to align future deliveries of LNG with our expected needs. We purchased LNG in the open market for the remainder of our needs in 2020, significantly reducing our LNG supply cost from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020.

We experienced lower than expected consumption by some of our customers in the second quarter of 2020, primarily as a result of unplanned maintenance at one of our customer’s facilities in Jamaica. As a result, we were unable to utilize a firm cargo purchased under our LNG supply agreement, incurring a loss of $18,906 on the sale of this cargo that was recognized during the second quarter of 2020.

Loss on mitigation sales for the year ended December 31, 2019 was $5,280 which was attributable to losses incurred associated with undelivered quantities of LNG under firm purchase commitments due to storage capacity constraints.

Depreciation and amortization

Depreciation and amortization for the year ended December 31, 2020 was $32,376, which increased $24,436 from $7,940 for the year ended December 31, 2019. The increase was primarily due to the following:

•

Increase in depreciation of $3,582 for our Old Harbour Facility that went into service in June 2019;

•

Increase in depreciation of $9,515 for the CHP Plant that went into service in March 2020;

•

Increase in depreciation of $4,484 for the San Juan Facility that went into service in July 2020;

•

Additional depreciation of $4,499 recognized on our Montego Bay Facility during the year. These assets were presented as direct financing leases prior to the adoption of ASC 842, and no depreciation for such assets was previously recorded.

Interest expense

Interest expense for the year ended December 31, 2020 was $65,723, which increased $46,311 from $19,412 for the year ended December 31, 2019, primarily as a result of the additional principal balances outstanding during 2020 under the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds, as compared to the Term Loan Facility (all defined below). When the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds were replaced by the Senior Secured Notes in September 2020, the outstanding principal balances totaled $980,000, as compared to the Term Loan Facility principal amount as of December 31, 2019 of $495,000, which had been extinguished in January 2020. As of December 31, 2020, we have issued $1,250,000 of Senior Secured Notes.

Other expense (income), net

Other expense (income), net for the year ended December 31, 2020 was $5,005, which increased $7,812 from income of ($2,807) for the year ended December 31, 2019, primarily as a result of the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG, a decrease in interest income, and an increase in unrealized loss on our investment in equity securities.

Loss on extinguishment of debt, net

Loss on extinguishment of debt was $33,062 for the year ended December 31, 2020 as a result of the extinguishment of the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds in September 2020, as well as the loss recognized upon the extinguishment of the Term Loan Facility in January 2020. Loss on extinguishment of debt for the year ended December 31, 2019 was $0 as we did not have any such transactions during the year.

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Tax expense

Tax expense for the year ended December 31, 2020 was $4,817, which increased $4,378 from a tax expense of $439 for the year ended December 31, 2019. During 2020, the CHP Plant began operations and we placed our assets at the San Juan Facility in service. Certain of our Jamaican operations had increased earnings for the year ended December 31, 2020 without any historical net operating losses to offset additional tax expense. We have recognized tax expense in Puerto Rico at a preferential tax rate due to our tax decree resulting in an effective tax rate lower than the U.S. federal income tax rate. We continue to have valuation allowances in many of our foreign jurisdictions and tax expense for earnings generated in many foreign jurisdictions has been limited.

Factors Impacting Comparability of Our Financial Results

Our historical results of operations and cash flows are not indicative of results of operations and cash flows to be expected in the future, principally for the following reasons:

•

Our historical financial results do not include significant projects that have recently been completed or are near completion. Our results of operations for the year ended December 31, 2020 include our Montego Bay Facility, Miami Facility, sales from our Old Harbour Facility to SJPC, and certain industrial end-users. The CHP Plant commenced commercial operations during March 2020, and our results now include revenue and results operations from sales of gas, power and steam from the CHP Plant. We also completed the development of our San Juan Facility in third quarter of 2020, and in the second quarter of 2020, we began to deliver natural gas to the San Juan Power Plant for PREPA to use in the commissioning of their assets. Our current results do not include revenue and operating results from other projects under development including the La Paz Facility, the Puerto Sandino Facility, or the Ireland Facility.

•

Our historical financial results do not reflect changes to our current long-term LNG supply agreement as well as new LNG supply agreements that will lower the cost of our LNG supply through 2030. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the year ended December 31, 2020. In June 2020, we entered into an agreement to terminate our obligation to purchase LNG from our supplier for the remainder of 2020 in exchange for a payment of $105,000, and for the remainder of 2020, we purchased all volumes needed for our operations on the open market, significantly reducing our LNG supply costs from $0.73 per gallon ($8.81 per MMBtu) for the year ended December 31, 2019 to $0.46 per gallon ($5.58 per MMBtu) for the year ended December 31, 2020. During 2020, we also entered into four LNG supply agreements for the purchase of approximately 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement.

•

Our historical financial results do not include the anticipated acquisitions of Hygo and GMLP as well as transaction and integration costs expected to be incurred associated with these acquisitions. Upon completion of the acquisition of Hygo, we expect to acquire the Sergipe Terminal, a 50% interest in the Sergipe Power Plant, as well as the Barcarena Terminal and the Santa Catarina Terminal that are currently in development. In addition, we expect to acquire one FSRU in service at the Sergipe Terminal and two operating LNG carriers which may be converted into FSRUs. Upon completion of the acquisition of GMLP, we expect to acquire a fleet of six FSRUs, four LNG carriers and an interest in a floating liquefaction vessel. The results of operations of Hygo and GMLP will begin to be included in our financial statements upon the closing of the acquisitions, expected in the first half of 2021. Our results of operations in 2021 will also include transaction costs associated with these acquisitions as well as costs incurred to integrate the operations of Hygo and GMLP into our business.

•

We no longer qualify as an emerging growth company or “EGC”. As an EGC we were able to take advantage of an exemption from providing an auditor’s attestation on our system of internal controls over financial reporting pursuant to Section 404(b) of the Sarbanes Oxley Act. Following the issuance of Senior Secured Notes in September 2020, we ceased to qualify as an EGC and can no longer take advantage of this exemption. We are also now required to accelerate the adoption of certain new or revised accounting pronouncements. Starting in 2020, we will incur additional costs associated with providing an auditor’s attestation report, adoption of accounting standards on an accelerated timeline, as well as additional audit costs resulting from PCAOB requirements.

Liquidity and Capital Resources

We believe we will have sufficient liquidity from proceeds from recent borrowings, access to additional capital sources and cash flow from operations to fund our capital expenditures and working capital needs for the next 12 months. We expect to fund our current operations and continued development of additional facilities through cash on hand and cash generated from operations. We may also elect to generate additional liquidity through future debt or equity issuances to fund developments and transactions. We have historically funded our developments through proceeds from our IPO and debt and equity financing as follows:

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•

Our IPO was completed on February 4, 2019, and we raised net proceeds of $268,010, inclusive of additional net proceeds raised from the exercise of the underwriter’s option to purchase additional shares and after deducting underwriting discounts and commissions and transaction costs.

•

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

•

In September 2019, we issued approximately $117,000 in Senior Secured Bonds and Senior Unsecured Bonds, and in December 2019, we issued an additional $63,000 in Senior Secured Bonds, which was fully funded by January 2020.

•

In January 2020, we borrowed $800,000 under the Credit Agreement and repaid the Term Loan Facility in full.

•

In September 2020, we issued $1,000,000 of Senior Secured Notes and repaid in full amounts due on the Credit Agreement, Senior Secured Bonds and Senior Unsecured Bonds. No principal payments are due on the Senior Secured Notes until maturity in 2025.

•

In December 2020, we received proceeds of $263,500 from the issuance of $250,000 of additional notes on the same terms as the Senior Secured Notes (subsequent to this issuance, these additional notes are included in the definition of Senior Secured Notes herein).

•

In December 2020, we issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs.

We have assumed total expenditures for all completed and existing projects to be approximately $1,181 million, with approximately $789 million having already been spent through December 31, 2020. This estimate represents the expenditures necessary to complete the La Paz Facility and the Puerto Sandino Facility, expected expenditures to serve new industrial end-users and other planned capital expenditures. We expect to be able to fund all such committed projects with a combination of cash on hand and cash flows from operations. Through December 31, 2020, we have spent approximately $159 million to develop the Pennsylvania Facility. Approximately $20 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $139 million, has been capitalized.

We have obtained debt financing commitments from Morgan Stanley Senior Funding, Inc. and Goldman Sachs Bank USA for loans in an aggregate principal amount of $1.7 billion, consisting of a $1.5 billion senior secured bridge facility (the “Bridge Loan”) and a $200 million senior secured revolving facility to pay, subject to the terms and conditions set forth therein, a portion of the cash purchase price in connection with the GMLP Merger, to refinance certain debt of GMLP and its subsidiaries, to pay related fees and expenses and for general corporate purposes. If NFE utilizes the Bridge Loan, the facility will bear a fixed interest rate of 6.25%, subject to a step-up of 50 basis points every three months. The Bridge Loan has a one-year term, is pre-payable without penalty and will automatically be converted into a seven-year term loan if it is not repaid in full at maturity. The senior secured revolving facility has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.

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Cash Flows

The following table summarizes the changes to our cash flows for the years ended December 31, 2020 and 2019, respectively:

	Year Ended December 31,
(in thousands)	2020			2019			Change
Cash flows from:
Operating activities	$	(125,566	)	$	(234,261	)	$	108,695
Investing activities		(157,631	)		(376,164	)		218,533
Financing activities		819,498			602,607			216,891
Net increase (decrease ) in cash, cash equivalents, and restricted cash	$	536,301		$	(7,818	)	$	544,119

Cash (used in) operating activities

Our cash flow used in operating activities was $125,566 for the year ended December 31, 2020, which decreased by $108,695 from $234,261 for the year ended December 31, 2019. The reduction in cash flow used in operating activities for the year ended December 31, 2020 was due to more favorable changes in working capital accounts. Fluctuations in inventory balances led to an increase in operating cash flows of $23,230 for the year ended December 31, 2020 compared to a $50,345 decrease in operating cash flows for the year ended December 31, 2019. The impact of increasing accounts payable and accrued liabilities on cash flows from operations was $55,514 for the year ended December 31, 2020 compared to $3,036 for the year ended December 31, 2019.

Cash (used in) investing activities

Our cash flow used in investing activities was $157,631 for the year ended December 31, 2020, which decreased by $218,533 from $376,164 for the year ended December 31, 2019. Cash outflows for investing activities during the year ended December 31, 2020 were primarily used to complete the CHP Plant and the San Juan Facility, as well as construction of the La Paz Facility.

Cash used in investing activities during the year ended December 31, 2019 significant capital expenditures for development of our Old Harbour Facility, CHP Plant, San Juan Facility and Pennsylvania Facility, as well as payments for significant outstanding amounts to our suppliers that were accrued as of December 31, 2018.

Cash provided by financing activities

Our cash flow provided by financing activities was $819,498 for the year ended December 31, 2020, which increased by $216,891 from $602,607 for the year ended December 31, 2019. Cash provided by financing activities during the year ended December 31, 2020 was due to proceeds received from the borrowings under the Senior Secured Notes of $1,250,000, the Credit Agreement of $800,000 and Senior Secured Bonds of $52,144. A portion of these proceeds from the Senior Secured Notes were used to fund the repayment of the Credit Agreement of $800,000, the Senior Secured Bonds and Senior Unsecured Bonds of $183,600 and the Term Loan Facility of $506,402. The proceeds received were further offset by transaction costs and other fees incurred to obtain the borrowings. In 2020, we also received proceeds from the issuance of Class A common stock of $291,922, offset by stock issuance costs of $1,107. Cash dividends of $33,742 were paid, partially offsetting financing inflows.

Cash flow provided by financing activities during the year ended December 31, 2019 were primarily consisted of the issuance of Senior Secured Bonds and Senior Unsecured Bonds of $117,000 in September 2019, additional borrowings under the Term Loan Facility of $220,000 in March 2019 and proceeds received from our IPO of $274,948 in February 2019.

Long-Term Debt

Senior Secured Notes

On September 2, 2020, the Company issued $1,000,000 of 6.75% senior secured notes in a private offering pursuant to Rule 144A under the Securities Act (the “Senior Secured Notes”). Interest is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2021; no principal payments are due until maturity on September 15, 2025. The Company may redeem the Senior Secured Notes, in whole or in part, at any time prior to maturity, subject to certain make-whole premiums.

The Senior Secured Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The Senior Secured Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The Senior Secured Notes also provide for customary events of default and prepayment provisions.

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We used a portion of the net cash proceeds received from the Senior Secured Notes to repay in full the outstanding principal and interest under the Credit Agreement, including related costs and expenses. We also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds, including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds. The redemption of the Senior Secured Bonds and Senior Unsecured Bonds was completed on September 21, 2020.

In connection with the issuance of the Senior Secured Notes, we incurred $17,937 in origination, structuring and other fees. Issuance costs of 13,909 were deferred as a reduction of the principal balance of the Senior Secured Notes on the consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the Senior Secured Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the Senior Secured Notes and will be amortized over the remaining term of the Senior Secured Notes. As a portion of the repayment of the Credit Agreement was a modification, we recorded $4,028 of third-party fees in Selling, general and administrative in the consolidated statements of operations and comprehensive loss.

On December 17, 2020, the Company issued $250,000 of additional notes on the same terms as the Senior Secured Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of Senior Secured Notes herein). Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,188. As of December 31, 2020, total remaining unamortized deferred financing costs were $10,439.

The Credit Agreement

On January 10, 2020, the Company entered into a credit agreement to borrow $800,000 in term loans (the “Credit Agreement”). The Credit Agreement was to mature in January 2023 with the full principal balance due upon maturity. Interest was payable quarterly and was based on a LIBOR rate divided by one minus the applicable reserve requirement, subject to a floor of 1.50%, plus a margin of 6.25%. The interest rate margin was to increase each year of the term by 1.50%. Outstanding balances could be prepaid at our option at any time without premium. We used a portion of the proceeds received to extinguish the Term Loan Facility.

We were required to comply with certain financial covenants as well as usual and customary affirmative and negative covenants, including limitations on liens and incurring additional indebtedness. The facility also provided for customary events of default and cure provisions.

In connection with obtaining the Credit Agreement and the extinguishment of the Term Loan Facility, the Company incurred $37,051 in origination, structuring and other fees which were recognized as a reduction of the principal balance of the Credit Agreement on the consolidated balance sheets. On September 2, 2020, we repaid the full amount outstanding using proceeds from the Senior Secured Notes. Certain holders of the Credit Agreement participated in the issuance of Senior Secured Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the Senior Secured Notes.

Term Loan Facility

On August 16, 2018, the Company entered into a credit agreement with a syndicate of two lenders to borrow up to an aggregate principal amount of $240,000. On December 31, 2018, the Company amended this credit agreement (as amended, the “Term Loan Facility”) to, among other things, (i) increase the amount available for borrowing thereunder from $240,000 to $500,000, (ii) extend the initial maturity date to December 31, 2019, (iii) modify certain provisions relating to restrictive covenants and existing financial covenants, and (iv) remove the mandatory prepayment required with the net proceeds received in connection with an IPO. As of December 31, 2018, the outstanding principal balance under the Term Loan Facility was $280,000.

On March 21, 2019, the Company drew an additional $220,000, bringing our total outstanding borrowings to $500,000 under the Term Loan Facility, and as of December 31, 2019, the total principal amount outstanding under the Term Loan Facility was $495,000.

All borrowings under the Term Loan Facility bore interest at a rate selected by us of either (i) LIBOR divided by one minus the applicable reserve requirement plus a spread of 4% or (ii) subject to a floor of 1%, a Base Rate equal to the higher of (a) the Prime Rate, (b) the Federal Funds Rate plus 1/2 of 1% or (c) the 1-month LIBOR rate plus 1.00% plus a spread of 3.0%. The Term Loan Facility was repayable in quarterly installments of $1,250 with a balloon payment due at maturity.

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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.

South Power Bonds

On September 2, 2019, NFE South Power Holdings Limited (“South Power”), a consolidated subsidiary of the Company, entered into a facility for the issuance of secured and unsecured bonds (the “Senior Secured Bonds” and “Senior Unsecured Bonds”, respectively) and subsequently issued $73,317 and $43,683 in Senior Secured Bonds and Senior Unsecured Bonds, respectively. The Senior Secured Bonds are secured by the CHP Plant and related receivables and assets, and the proceeds will be used to fund the completion of the CHP Plant and to reimburse shareholder advances. In the fourth quarter of 2019, South Power issued an additional $63,000 in Senior Secured Bonds. We received $10,856 of the proceeds in 2019 and received the remaining proceeds of $52,144 in January 2020.

The Senior Secured Bonds bore interest at an annual fixed rate of 8.25% and matured 15 years from the closing date of each issuance. No principal payments were due for the first seven years. Beginning in 2026, quarterly principal payments of approximately 1.6% of the original principal amount were due, with a 50% balloon payment due upon maturity. Interest payments on outstanding principal balances were due quarterly.

The Senior Unsecured Bonds bore interest at an annual fixed rate of 11.00% and matured in September 2036. No principal payments were due for the first nine years. Beginning in 2028, principal payments were due quarterly on an escalating schedule. Interest payments on outstanding principal balances were due quarterly.

South Power was required to comply with certain financial covenants as well as customary affirmative and negative covenants, including limitations on incurring additional indebtedness. The facility also provided for customary events of default, prepayment and cure provisions.

The Company paid approximately $3,892 of fees in connection with the issuance of Senior Secured Bonds and Senior Unsecured Bonds. These fees were capitalized on a pro-rata basis as a reduction of the Senior Secured Bonds and Senior Unsecured Bonds on the consolidated balance sheets. On September 21, 2020, the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the Senior Secured Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds, the Company recognized a loss on extinguishment of debt of $7,195 in the consolidated statements of operations and comprehensive loss, including the write-off of $3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $3,601.

Off Balance Sheet Arrangements

As of December 31, 2020 and 2019, we had no off-balance sheet arrangements that may have a current or future material effect on our consolidated financial position or operating results.

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Contractual Obligations

We are committed to make cash payments in the future pursuant to certain contracts. The following table summarizes certain contractual obligations in place as of December 31, 2020:

(in thousands)	Total		Less than 1 year		Years 2 to 3		Year 4 to 5		More than 5 years
Long-term debt obligations	$	1,675,203	$	87,703	$	168,750	$	1,418,750	$	-
Purchase obligations		2,490,347		376,096		724,588		724,090		665,573
Lease obligations		191,991		47,135		56,066		36,006		52,784
Total	$	4,357,541	$	510,934	$	949,404	$	2,178,846	$	718,357

Long-term debt obligations

For information on our long-term debt obligations, see “—Liquidity and Capital Resources—Long-Term Debt.” The amounts included in the table above are based on the total debt balance, scheduled maturities, and interest rates in effect as of December 31, 2020.

Purchase obligations

The Company is party to contractual purchase commitments for the purchase, production and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop our terminals and related infrastructure. Our commitments to purchase LNG and natural gas are principally take-or-pay contracts, which require the purchase of minimum quantities of LNG and natural gas, and these commitments are designed to assure sources of supply and are not expected to be in excess of normal requirements. For purchase commitments priced based upon an index such as Henry Hub, the amounts shown in the table above are based on the spot price of that index as of December 31, 2020.

In 2020, we entered into four LNG supply agreements for the purchase of 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030. Between 2022 and 2025, the total annual commitment under these agreements is approximately 68 TBtu per year, reducing to approximately 28 TBtu per year from 2026 to 2029. The amounts disclosed above also include the commitment to purchase 12 firm cargoes in 2021 under a supply contract executed in December 2018.

Lease obligations

Future minimum lease payments under non-cancellable lease agreements, inclusive of fixed lease payments for renewal periods we are reasonably certain will be exercised, are included in the above table. Fixed lease payments for short-term leases are also included in the table above. Our lease obligations are primarily related to LNG vessel time charters, marine port leases, ISO tank leases, office space and a land lease.

The Company currently has five vessels under time charter leases with non-cancellable terms ranging from nine months to seven years. The lease commitments in the table above include only the lease component of these arrangements due over the non-cancellable term and does not include any operating services.

We have leases for port space and a land site for the development of our facilities. Terms for leases of port space range from 20 to 25 years. The land site lease is held with an affiliate of the Company and has a remaining term of approximately five years with an automatic renewal term of five years for up to an additional 20 years.

During 2020, we executed multiple lease agreements for the use of ISO tanks, and we expect to begin to receive these ISO tanks and for the lease terms to commence beginning in the first quarter of 2021. The lease term for each of these leases is five years, and expected payments under these lease agreements have been included in the above table.

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

Summary of Critical Accounting Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management evaluates its estimates and related assumptions regularly and will continue to do so as we further grow our business. We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.

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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. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is typically delivered in containers transported by truck to customer sites. Revenue from sales of LNG delivered by truck is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, either when the containers are shipped or delivered to the customers’ storage facilities, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, we have presented Operating revenue on an aggregated basis.

We have concluded that variable consideration included in these agreements meets the exception for allocating variable consideration to each unit sold under the contract. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer.

Our contracts with customers to supply LNG or natural gas may contain a lease of equipment. We allocate consideration received from customers between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. We estimate the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term. The estimated fair value of the leased equipment, as a percentage of the estimated total revenue from LNG or natural gas and leased equipment at inception, will establish the allocation percentage to determine the fixed lease payments and the amount to be accounted for under the revenue recognition guidance.

The leases of certain facilities and equipment to customers are accounted for as finance or operating leases. The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net, on the consolidated balance sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and is included in Other revenue in the consolidated statements of operations and comprehensive loss. The principal components of the lease payment are reflected as a reduction to the net investment in the finance lease. For our operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the consolidated statements of operations and comprehensive loss.

In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes development services revenue recognized from the construction, installation and commissioning of equipment to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as we transfer control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under development until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and we recognize revenue for the interest income component over the term of the financing as Other revenue.

Development services are typically included in arrangements that include other distinct performance obligations, and we allocate the transaction price to each performance obligation based on its standalone selling price (“SSP”) in relation to the aggregate value of the SSP of all performance obligations in the arrangement. Some of our performance obligations have observable inputs that are used to determine the SSP of those distinct performance obligations. Where SSP is not directly observable, we primarily determine the SSP using the cost-plus approach. In the circumstances when available information to determine SSP is highly variable or uncertain, we use the residual approach.

Impairment of long-lived assets

We perform a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where we operate, unfavorable events impacting the supply chain for LNG to our operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract or the introduction of newer technology. We exercise judgment in determining if any of these events represent an impairment indicator requiring a recoverability assessment.

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Our business model requires investments in infrastructure often concurrently with our customer’s investments in power generation or other assets to utilize LNG. Our costs to transport and store LNG are based upon our customer’s contractual commitments once their assets are fully operational. We expect revenue under these contracts to exceed construction and operational costs, based on the expected term and revenue of these contracts. Additionally, our infrastructure assets are strategically located to provide critical inputs to our committed customer’s operations and our locations allow us to expand to additional opportunities within existing markets. These projects are subject to risks related to successful completion, including those related to government approvals, site identification, financing, construction permitting and contract compliance.

We have considered that the market price of LNG can vary widely, including recent decreases throughout 2019 and 2020. Due to the decline in LNG prices, we executed three long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower than inventory purchased under our contract with our current supplier. Further, we were able to take advantage of lower market pricing for LNG to supply our operations for the second half of 2020, resulting in an overall lower average cost of LNG. Our long-term, take-or pay contracts to deliver natural gas or LNG to our customers also limit our exposure to fluctuations in natural gas and LNG as our pricing is based on the Henry Hub index plus a contractual spread. Based on the long-term nature of our contracts and the market value of the underlying assets, we do not believe that changes in the price of LNG indicate that a recoverability assessment of our assets is necessary. Further, we plan to utilize our own liquefaction facilities to manufacture our own LNG at attractive prices, secure LNG to supply our expanding operations and reduce our exposure to future LNG price variations in the long term.

We have also considered the impacts of the ongoing COVID-19 pandemic, including the restrictions that governments may put in place and the resulting direct and indirect economic impacts, on our current operations and expected development budgets and timelines. We primarily operate under long-term contracts with customers, many of which contain fixed minimum volumes that must be purchased on a “take-or-pay” basis, even in cases when our customer’s consumption has decreased. We have not changed our payment terms with these customers, and there has not been any deterioration in the timing or volume of collections.

Based on the essential nature of the services we provide to support power generation facilities, our development projects have not currently been significantly impacted by responses to the COVID-19 pandemic. We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicators that a recoverability assessment for our assets should be performed.

The COVID-19 pandemic has also significantly impacted energy markets, and the price of oil has traded at historic low prices in 2020. Future expansion of our business is dependent upon LNG being a competitive source of energy and available at a lower cost than the cost to deliver other alternative energy sources, such as diesel or other distillate fuels. We do not believe that oil prices will remain at their historic low levels as evidenced by recent recovery, and we believe that LNG and natural gas will remain a competitive fuel source for customers.

When performing a recoverability assessment, the Company measures whether the estimated future undiscounted net cash flows expected to be generated by the asset exceeds its carrying value. In the event that an asset does not meet the recoverability test, the carrying value of the asset will be adjusted to fair value resulting in an impairment charge. Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources.

Share-based compensation

We estimate the fair value of RSUs and performance stock units (“PSUs”) granted to employees and non-employees on the grant date based on the closing price of the underlying shares on the grant date and other fair value adjustments to account for a post-vesting holding period. These fair value adjustments were estimated based on the Finnerty model.

As of December 31, 2020, management determined that it was not probable that the performance condition for our outstanding PSUs would be met. For these awards, compensation cost and the number of PSUs ultimately earned remains variable and compensation cost for these awards is recorded once achievement of the performance conditions becomes probable through the requisite service period. A cumulative adjustment to share-based compensation expense is recorded in the period that achievement of performance conditions becomes probable.

Recent Accounting Standards

For descriptions of recently issued accounting standards, see “Note 3 - Adoption of new and revised standards” to our notes to consolidated financial statements included elsewhere in this Annual Report.

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Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

In the normal course of business, the Company encounters several significant types of market risks including commodity and interest rate risks.

Commodity Price Risk

Commodity price risk is the risk of loss arising from adverse changes in market rates and prices. We are able to limit our exposure to fluctuations in natural gas prices as our pricing in contracts with customers is based on the Henry Hub index price plus a contractual spread. Our exposure to market risk associated with LNG price changes may adversely impact our business. We do not currently have any derivative arrangements to protect against fluctuations in commodity prices, but to mitigate the effect of fluctuations in LNG prices on our operations, we may enter into various derivative instruments.

Interest Rate Risk

The Senior Secured Notes were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the Senior Secured Notes but such a change would have no impact on our results of operations or cash flows. A 100-basis point increase or decrease in the market interest rate would decrease or increase the fair value of our fixed rate debt by approximately $52 million. The sensitivity analysis presented is based on certain simplifying assumptions, including instantaneous change in interest rate and parallel shifts in the yield curve. We do not currently have any derivative arrangements to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

Foreign Currency Exchange Risk

We primarily conduct our operations in U.S. dollars, and as such, our results of operations and cash flows have not materially been impacted by fluctuations due to changes in foreign currency exchange rates. We currently incur a limited amount of costs in foreign jurisdictions that are paid in local currencies, but we expect our international operations to continue to grow in the near term. We do not currently have any derivative arrangements to protect against fluctuations in foreign exchange rates, but to mitigate the effect of fluctuations in exchange rates on our operations, we may enter into various derivative instruments.

Item 8.

Financial Statements and Supplementary Data.

Our Consolidated Financial Statements, together with the report of our independent registered public accounting firm, begin on page F-1 of this Annual Report and are incorporated herein by reference.

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.

None.

Item 9A.

Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2020. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2020 at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during our last quarter of 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

As of December 31, 2020, our management assessed the effectiveness of our internal control over financial reporting based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in “Internal Control – Integrated Framework (2013)”. Based on this assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2020.

The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by EY, an independent registered public accounting firm, as stated in their report, which appears herein.

Item 9B.

Other Information.

None.

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PART III

Item 10.

Directors, Executive Officers and Corporate Governance.

The information required by this Item 10 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholders and is incorporated herein by reference.

Item 11.

Executive Compensation

The information required by this Item 11 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholders and is incorporated herein by reference.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters.

The information required by this Item 12 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholders and is incorporated herein by reference.

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

The information required by this Item 13 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholders and is incorporated herein by reference.

Item 14.

Principal Accounting Fees and Services.

The information required by this Item 14 is set forth in the Company’s Proxy Statement to be filed with the SEC within 120 days after December 31, 2020 in connection with our 2021 annual meeting of shareholders and is incorporated herein by reference.

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PART IV

Item 15.

Exhibits, Financial Statement Schedules.

(a)(1)

Financial Statements.

See “Index to Financial Statements” set forth on page F-1.

(2)	Financial Statement Schedules.

See Schedule II set forth on page F-31.

(b)

Exhibits.

The exhibits required to be filed by this Item 15(b) are set forth in the Exhibit Index included below.

Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated as of January 13, 2021, by and among NFE, GMLP Merger Sub, GP Buyer, GMLP and the General Partner (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on January 20, 2021)
2.2		Transfer Agreement, dated as of January 13, 2021, by and among GP Buyer, GLNG and the General Partner (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on January 20, 2021)
2.3		Agreement and Plan of Merger, dated as of January 13, 2021, by and among NFE, Hygo Merger Sub, Hygo and the Hygo Shareholders (incorporated by reference to Exhibit 2.3 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on January 20, 2021)
3.1		Certificate of Formation of New Fortress Energy LLC (incorporated by reference to Exhibit 3.1 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the Commission on November 9, 2018)
3.2		Certificate of Amendment to Certificate of Formation of New Fortress Energy LLC (incorporated by reference to Exhibit 3.2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the Commission on November 9, 2018)
3.3		First Amended and Restated Limited Liability Company Agreement of New Fortress Energy LLC, dated February 4, 2019 (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
3.4		Certificate of Incorporation of New Fortress Energy Inc. (incorporated herein by reference to Exhibit 99.3 of the Company’s Quarterly Report on Form 10-Q filed on August 4, 2020)
3.5		Bylaws of New Fortress Energy Inc. (incorporated herein by reference to Exhibit 99.4 of the Company’s Quarterly Report on Form 10-Q filed on August 4, 2020)
4.1		Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 99.1 to the Registrant's Current Report on Form 8-K (File No. 001-38790), filed with the Commission on August 7, 2020)
4.2		Indenture, dated September 2, 2020, by and among New Fortress Energy Inc., the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (File No. 001-38790), filed with the Commission on September 2, 2020)
4.3		First Supplemental Indenture, dated December 17, 2020, by and among New Fortress Energy Inc., the subsidiary guarantors from time to time party thereto and U.S. Bank National Association, as trustee and as notes collateral agent (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (File No. 001-38790), filed with the Commission on December 18, 2020)
4.4		Pledge and Security Agreement, by and among New Fortress Energy Inc., the subsidiary guarantees from time to time party thereto, and U.S. Bank National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (File No. 001-38790), filed with the Commission on September 2, 2020)
10.1		Contribution Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Intermediate LLC, New Fortress Energy Holdings LLC, NFE Atlantic Holdings LLC and NFE Sub LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.2		Amended and Restated Limited Liability Company Agreement of New Fortress Intermediate LLC, dated February 4, 2019 (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.3†		New Fortress Energy LLC 2019 Omnibus Incentive Plan (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-8 (File No. 333-229507), filed with the Commission on February 4, 2019)
10.4†		Form of Director Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 10.4 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on December 24, 2018)
10.5†		Offer Letter, dated March 14, 2017, by and between NFE Management LLC and Christopher Guinta (incorporated by reference to Exhibit 10.5 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 14, 2019)
10.6†		Offer Letter, dated August 30, 2018, by and between NFE Management LLC and Michael J. Utsler (incorporated by reference to Exhibit 10.6 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 14, 2019)
10.7		Shareholders’ Agreement, dated February 4, 2019, by and among New Fortress Energy LLC, New Fortress Energy Holdings LLC, Wesley R. Edens and Randal A. Nardone (incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.8		Administrative Services Agreement, dated February 4, 2019, by and between New Fortress Intermediate LLC and FIG LLC (incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.9		Gas Sales Agreement, dated August 5, 2015, by and among New Fortress Energy LLC and Jamaica Public Service Company Limited (incorporated by reference to Exhibit 10.12 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the Commission on November 9, 2018)]

Table of Contents

Exhibit Number		Description
‡10.10		Gas Sales Agreement, dated August 5, 2015, by and between New Fortress Energy LLC and Jamaica Public Service Company Limited (incorporated by reference to Exhibit 10.12 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the Commission on November 9, 2018)
‡10.11		First Amendment to Gas Sales Agreement, dated May 23, 2016, by and between NFE North Holdings Limited and Jamaica Public Service Company Limited (incorporated by reference to Exhibit 10.13 to the Registrant’s Registration Statement on Form S-1 (File No. 333-228339), filed with the Commission on November 9, 2018)
10.12†		Indemnification Agreement (Edens) (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.13†		Indemnification Agreement (Guinta) (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.14†		Indemnification Agreement (Utsler) (incorporated by reference to Exhibit 10.6 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.15†		Indemnification Agreement (Catterall) (incorporated by reference to Exhibit 10.7 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.16†		Indemnification Agreement (Grain) (incorporated by reference to Exhibit 10.8 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.17†		Indemnification Agreement (Griffin) (incorporated by reference to Exhibit 10.9 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.18†		Indemnification Agreement (Mack) (incorporated by reference to Exhibit 10.10 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.19†		Indemnification Agreement (Nardone) (incorporated by reference to Exhibit 10.11 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.20†		Indemnification Agreement (Wanner) (incorporated by reference to Exhibit 10.12 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)
10.21†		Indemnification Agreement (Wilkinson) (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on February 5, 2019)

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Exhibit Number		Description
10.22		Master LNG Sale and Purchase Agreement, dated December 20, 2016, by and between Centrica LNG Company Limited and NFE North Trading Limited (incorporated by reference to Exhibit 10.16 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 14, 2019)
10.23		Engineering, Procurement and Construction Agreement for the Marcellus LNG Production Facility I, dated January 8, 2019, by and between Bradford County Real Estate Partners LLC and Black & Veatch Construction, Inc. (incorporated by reference to Exhibit 10.17 to the Registrant’s Registration Statement on Form S-1/A (File No. 333-228339), filed with the Commission on January 25, 2019)
10.24†		Indemnification Agreement, dated as of March 17, 2019, by and between New Fortress Energy LLC and Yunyoung Shin (incorporated by reference to Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K (File 001-38790), filed with the Commission on March 26, 2019)
10.25		Mutual Agreement, dated June 3, 2020, by and among New Fortress Energy LLC, Fortress Equity Partners GP, LLC, WRE 2012 Trust LLC, FEP HoldCo LLC, Wesley R Edens, Randal A Nardone, NFE SMRS Holdings LLC and NFE Sub LLC (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on June 9, 2020)
10.26		Support Agreement, dated as of January 13, 2021, by and among NFE, GMLP, GLNG and the General Partner (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K (File No. 001-38790), filed with the Commission on January 20, 2021)
21.1*		List of Subsidiaries of New Fortress Energy Inc.
23.1*		Consent of Ernst & Young L.L.P.
31.1*		Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certifications by Chief Executive Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
32.2**		Certifications by Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

*	Filed as an exhibit to this Annual Report

**	Furnished as an exhibit to this Annual Report

†	Compensatory plan or arrangement

‡	Confidential treatment was granted with respect to certain portions of this exhibit. Omitted portions filed separately with the SEC.

Item 16.

Form 10-K Summary.

None.

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SIGNATURES

Pursuant to the requirements of 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	NEW FORTRESS ENERGY INC.
Date: March 16, 2021
	By:	/s/ Christopher S. Guinta
	Name:	Christopher S. Guinta
	Title:	Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.

Name	Title	Date

Wesley R. Edens	Chief Executive Officer and Chairman (Principal Executive Officer)	March 16, 2021


Christopher S. Guinta	Chief Financial Officer (Principal Financial Officer)	March 16, 2021
	Chief Financial Officer (Principal Financial Officer)

Yunyoung Shin	Chief Accounting Officer (Principal Accounting Officer)	March 16, 2021
	Chief Accounting Officer (Principal Accounting Officer)

Randal A. Nardone	Director	March 16, 2021

C. William Griffin	Director	March 16, 2021

John J. Mack	Director	March 16, 2021

Matthew Wilkinson	Director	March 16, 2021

David J. Grain	Director	March 16, 2021

Desmond Iain Catterall	Director	March 16, 2021

Katherine E. Wanner	Director	March 16, 2021

Table of Contents

Index to Consolidated Financial Statements

	Page
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets		F-8
Consolidated Statements of Operations and Comprehensive Loss		F-9
Consolidated Statements of Changes in Stockholders’ Equity		F-10
Consolidated Statements of Cash Flows		F-11
Notes to Consolidated Financial Statements		F-12

F-1

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of New Fortress Energy Inc.

Opinion on Internal Control Over Financial Reporting

We have audited New Fortress Energy Inc.’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework (the COSO criteria). In our opinion, New Fortress Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the accompanying consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). Our report dated March 16, 2021 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

F-2

Table of Contents

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Philadelphia, Pennsylvania

March 16, 2021

F-3

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of New Fortress Energy Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of New Fortress Energy Inc. (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and the financial statement schedule listed in the Index at Item 15(a)(2) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission 2013 framework and our report dated March 16, 2021 expressed an unqualified opinion thereon.

Adoption of ASU No. 2016-02

As discussed in Note 3 to the consolidated financial statements, the Company changed its method of accounting for leases in 2020 due to the adoption of ASU No. 2016-02, Leases.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

F-4

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Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

	Revenue Recognition – Identification of Distinct Performance Obligations and Leases

Description of the Matter	As described in Note 2(p) to the consolidated financial statements, the Company’s contracts with customers may contain one or several performance obligations to provide goods or services or may contain a lease. At inception or upon amendment, management performs an evaluation to identify the obligations within the contract and determine the authoritative guidance applicable to such obligations. The Company allocates consideration received from customers between lease and non-lease components based on the relative fair value of each component. Auditing management’s identification of performance and other obligations in each contract was challenging as it involved complex judgement to identify all promised goods and services and determining whether the customer can benefit from the promised goods or services on their own or on a combined basis. In addition, auditing management’s determination of whether a contract is or contains a lease required judgement to determine which party to the agreement controls how and for what purpose the underlying asset is used.

How We Addressed the Matter

in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company's revenue recognition process, including controls over the evaluation of new and amended customer contracts and the identification of distinct performance obligations and equipment leases.

Our audit procedures included, among others, evaluating the Company’s assessment of the authoritative guidance applicable to its customer contracts, inspecting contracts entered into or amended during the period, and evaluating management’s interpretation of certain contract provisions when identifying and determining distinct performance obligations and equipment leases. For example, we selected a sample of new and amended customer contracts executed in the current year and compared the identified promised goods and services, including lease components, to the analyses used by management to measure and allocate arrangement consideration. We also conducted meetings with various personnel at the Company responsible for negotiating the contract and overseeing the delivery of the performance obligations in order to understand the nature of the explicit and implicit promised goods and services as well as to understand whether the promises were capable of being distinct and distinct in the context of the contract. For leases elements, this evaluation included understanding whether the customer controls how and for what purpose the underlying equipment is used.

F-5

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	Impairment Assessment of Long-Lived Assets

Description of the Matter	As described in Note 2(k) to the consolidated financial statements, the Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators may include, but are not limited to, factors such as adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for liquified natural gas (“LNG”) to the Company’s operations, early termination of a significant customer contract, the introduction of newer technology, or a decision to discontinue an in-process development project. When such indicators are identified, management determines if long-lived assets or asset groups are impaired by comparing the related undiscounted expected future cash flows to its carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Auditing management’s determination of whether impairment indicators exist such that a recoverability test of the Company’s long-lived assets is required, was highly subjective and involves significant judgment. For instance, auditing management’s assessment of events or changes in circumstances that may be an indicator that an asset group is not recoverable was challenging due to the judgment applied in both the identification of such factors, and the evaluation of whether the factors have an impact on the recovery of the carrying value of the asset group.

How We Addressed the Matter

in Our Audit

We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s impairment assessment process. This included management’s controls to review for asset groups that may have been impacted by the impairment indicators described above.

To test the Company’s evaluation of potential indicators of impairment of its long- lived assets, our audit procedures included, among others, assessing the methodologies and testing the completeness and accuracy of the Company’s analysis of events or changes in circumstances. For example, we inquired of management (including project development personnel) to understand their evaluation of changes in the regulatory environments of the jurisdictions in which the Company operates and their impact on the recoverability of the related long-lived assets and asset groups. We also obtained capital budgets and construction bids, among other evidence, to understand management’s plans with respect to in-process development projects. We considered information about Company’s projects from external sources that support or provide contrary evidence to management’s evaluation of potential impairment indicators.

F-6

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/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2016.

Philadelphia, Pennsylvania

March 16, 2021

F-7

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New Fortress Energy Inc.

Consolidated Balance Sheets

As of December 31, 2020 and 2019

(in thousands of U.S. dollars, except share and per share amounts)

	December 31, 2020			December 31, 2019
Assets
Current assets
Cash and cash equivalents	$	601,522		$	27,098
Restricted cash		12,814			30,966
Receivables, net of allowances of $98 and $0, respectively		76,544			49,890
Inventory		22,860			63,432
Prepaid expenses and other current assets, net		48,270			39,734
Total current assets		762,010			211,120

Restricted cash		15,000			34,971
Construction in progress		234,037			466,587
Property, plant and equipment, net		614,206			192,222
Right-of-use assets		141,347			-
Intangible assets, net		46,102			43,540
Finance leases, net		7,044			91,174
Deferred tax assets, net		2,315			34
Other non-current assets, net		86,030			84,166
Total assets	$	1,908,091		$	1,123,814

Liabilities
Current liabilities
Accounts payable	$	21,331		$	11,593
Accrued liabilities		90,352			54,943
Current lease liabilities		35,481			-
Due to affiliates		8,980			10,252
Other current liabilities		35,006			25,475
Total current liabilities		191,150			102,263

Long-term debt		1,239,561			619,057
Non-current lease liabilities		84,323			-
Deferred tax liabilities, net		2,330			241
Other long-term liabilities		15,641			14,929
Total liabilities		1,533,005			736,490

Commitments and contingences (Note 17)

Stockholders’ equity
Class A common stock, $0.01 par value, 750.0 million shares authorized, 174.6 million issued and outstanding as of December 31, 2020		1,746			-
Class A shares, 0 shares issued and outstanding as of December 31, 2020; 23.6 million shares issued and outstanding as of December 31, 2019		-			130,658
Class B shares, 0 shares issued and outstanding as of December 31, 2020; 144.3 million shares, issued and outstanding as of December 31, 2019		-			-
Additional paid-in capital		594,534			-
Accumulated deficit		(229,503	)		(45,823	)
Accumulated other comprehensive income (loss)		182			(30	)
Total stockholders’ equity attributable to NFE		366,959			84,805
Non-controlling interest		8,127			302,519
Total stockholders’ equity		375,086			387,324
Total liabilities and stockholders’ equity	$	1,908,091		$	1,123,814

The accompanying notes are an integral part of these consolidated financial statements.

F-8

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New Fortress Energy Inc.

Consolidated Statements of Operations and Comprehensive Loss

For the years ended December 31, 2020, 2019 and 2018

(in thousands of U.S. dollars, except share and per share amounts)

	Year Ended December 31,
	2020			2019			2018
Revenues
Operating revenue	$	318,311		$	145,500		$	96,906
Other revenue		133,339			43,625			15,395
Total revenues		451,650			189,125			112,301


Operating expenses
Cost of sales		278,767			183,359			95,742
Operations and maintenance		47,581			26,899			9,589
Selling, general and administrative		124,170			152,922			62,137
Contract termination charges and loss on mitigation sales		124,114			5,280			-
Depreciation and amortization		32,376			7,940			3,321
Total operating expenses		607,008			376,400			170,789
Operating loss		(155,358	)		(187,275	)		(58,488	)
Interest expense		65,723			19,412			11,248
Other expense (income), net		5,005			(2,807	)		(784	)
Loss on extinguishment of debt, net		33,062			-			9,568
Loss before taxes		(259,148	)		(203,880	)		(78,520	)
Tax expense (benefit)		4,817			439			(338	)
Net loss		(263,965	)		(204,319	)		(78,182	)
Net loss attributable to non-controlling interest		81,818			170,510			106
Net loss attributable to stockholders	$	(182,147	)	$	(33,809	)	$	(78,076	)

Net loss per share – basic and diluted	$	(1.71	)	$	(1.62	)

Weighted average number of shares outstanding – basic and diluted		106,654,918			20,862,555

Other comprehensive loss:
Net loss	$	(263,965	)	$	(204,319	)	$	(78,182	)
Unrealized (gain) loss on currency translation adjustment		(2,005	)		219			-
Unrealized loss on available-for-sale investment		-			-			2,677
Comprehensive loss		(261,960	)		(204,538	)		(80,859	)
Comprehensive loss attributable to non-controlling interest		80,025			170,699			106
Comprehensive loss attributable to stockholders	$	(181,935	)	$	(33,839	)	$	(80,753	)

The accompanying notes are an integral part of these consolidated financial statements.

F-9

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New Fortress Energy Inc.

Consolidated Statements of Changes in Stockholders’ Equity

For the years ended December 31, 2020, 2019 and 2018

(in thousands of U.S. dollars, except per share amounts)

	Members’ Capital						Class A shares						Class B shares					Class A common stock					Additional paid-in			Stock subscription			Accumulated			Accumulated other comprehensive			Non-controlling			Total stockholders’
	Units			Amounts			Shares			Amount			Shares			Amount		Shares			Amount		capital			receivable			deficit			(loss) income			Interest			equity
Balance as of January 1, 2018		65,665,037		$	406,591			-		$	-			-		$	-		-		$	-	$	-		$	(50,000	)	$	(80,347	)	$	2,666		$	-		$	278,910
Net loss		-			-			-			-			-			-		-			-		-			-			(78,076	)		-			(106	)		(78,182	)
Other comprehensive loss		-			-			-			-			-			-		-			-		-			-			-			(2,677	)		-			(2,677	)
Capital contributions		665,843			20,150			-			-			-			-		-			-		-			-			-			-			-			20,150
Stock subscription receivable		1,652,215			-			-			-			-			-		-			-		-			50,000			-			-			-			50,000
Acquisition of Shannon LNG		-			-			-			-			-			-		-			-		-			-			-			-			14,446			14,446
Balance as of December 31, 2018		67,983,095			426,741			-			-			-			-		-			-		-			-			(158,423	)		(11	)		14,340			282,647
Activity prior to the IPO and related organizational transactions:
Net loss		-			-			-			-			-			-		-			-		-			-			(7,923	)		11			(91	)		(8,003	)
Effects of the IPO and related organizational transactions:
Issuance of Class A shares in the IPO, net of underwriting discount and offering costs		-			-			20,837,272			32,136			-			-		-			-		-			-			-			-			235,874			268,010
Effects of the reorganization transactions		(67,983,095	)		(426,741	)		-			51,092			147,058,824			-		-			-		-			-			146,420			-			229,229			-
Activity subsequent to the IPO and related organizational transactions:
Net loss		-			-			-			-			-			-		-			-		-			-			(25,897	)		-			(170,419	)		(196,316	)
Other comprehensive loss		-			-			-			-			-			-		-			-		-			-			-			(30	)		(189	)		(219	)
Share-based compensation expense		-			-			-			41,205			-			-		-			-		-			-			-			-			-			41,205
Exchange of NFI Units		-			-			2,716,252			6,225			(2,716,252	)		-		-			-		-			-			-			-			(6,225	)		-
Issuance of shares for vested RSUs		-			-			53,572			-			-			-		-			-		-			-			-			-			-			-
Balance as of December 31, 2019		-			-			23,607,096			130,658			144,342,572			-		-			-		-			-			(45,823	)		(30	)		302,519			387,324
Cumulative effect of accounting change		-			-			-			-			-			-		-			-		-			-			(1,533	)		-			(7,780	)		(9,313	)
Class A stock issued, net of issuance costs		-			-			-			-			-			-		5,882,352			59		290,712			-			-			-			-			290,771
Net loss		-			-			-			-			-			-		-			-		-			-			(182,147	)		-			(81,818	)		(263,965	)
Other comprehensive income		-			-			-			-			-			-		-			-		-			-			-			212			1,793			2,005
Share-based compensation expense		-			-			-			4,430			-			-		-			-		4,313			-			-			-			-			8,743
Issuance of shares for vested RSUs		-			-			1,224,436			-			-			-		160,317			-		-			-			-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		-			-			-			-			-			-		(593,911	)		-		(6,468	)		-			-			-			-			(6,468	)
Exchange of NFI units		-			-			144,342,572			206,587			(144,342,572	)		-		-			-		-			-			-			-			(206,587	)		-
Conversion from LLC to Corporation		-			-			(169,174,104	)		(341,675	)		-			-		169,174,104			1,687		339,988			-			-			-			-			-
Dividends		-			-			-			-			-			-		-			-		(34,011	)		-			-			-			-			(34,011	)
Balance as of December 31, 2020		-		$	-			-		$	-			-		$	-		174,622,862		$	1,746	$	594,534		$	-		$	(229,503	)	$	182		$	8,127		$	375,086

The accompanying notes are an integral part of these consolidated financial statements.

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New Fortress Energy Inc.

Consolidated Statements of Cash Flows

For the years ended December 31, 2020, 2019 and 2018

(in thousands of U.S. dollars)

	Year Ended December 31,
	2020			2019			2018
Cash flows from operating activities
Net loss	$	(263,965	)	$	(204,319	)	$	(78,182	)
Adjustments for:
Amortization of deferred financing costs		10,519			5,873			4,023
Depreciation and amortization		33,303			8,641			4,034
Non-cash contract termination charges and loss on mitigation sales		19,114			2,622			-
Loss on extinguishment and financing expenses		37,090			-			3,188
Deferred taxes		2,754			392			(345	)
Share-based compensation		8,743			41,205			-
Other		4,341			1,247			439
Changes in operating assets and liabilities:
(Increase) in receivables		(26,795	)		(19,754	)		(9,516	)
Decrease (Increase) in inventories		23,230			(50,345	)		(4,807	)
(Increase) in other assets		(35,927	)		(39,344	)		(28,338	)
Decrease in right-of-use assets		41,452			-			-
Increase in accounts payable/accrued liabilities		55,514			3,036			12,232
(Decrease) Increase in amounts due to affiliates		(1,272	)		5,771			2,390
(Decrease) in lease liabilities		(42,094	)		-			-
Increase in other liabilities		8,427			10,714			1,655
Net cash used in operating activities		(125,566	)		(234,261	)		(93,227	)

Cash flows from investing activities
Capital expenditures		(156,995	)		(377,051	)		(181,151	)
Acquisition of consolidated subsidiary		-			-			(4,028	)
Other investing activities		(636	)		887			724
Net cash used in investing activities		(157,631	)		(376,164	)		(184,455	)

Cash flows from financing activities
Proceeds from borrowings of debt		2,095,269			347,856			280,600
Payment of deferred financing costs		(36,499	)		(8,259	)		(14,026	)
Repayment of debt		(1,490,002	)		(5,000	)		(76,520	)
Proceeds from IPO		-			274,948			-
Proceeds from issuance of Class A common stock		291,992			-
Payments related to tax withholdings for share-based compensation		(6,413	)		-			-
Payment of dividends		(33,742	)		-			-
Capital contributed from Members		-			-			20,150
Collection of subscription receivable		-			-			50,000
Payment of stock issuance costs		(1,107	)		(6,938	)		-
Net cash provided by financing activities		819,498			602,607			260,204

Net increase (decrease) in cash, cash equivalents and restricted cash		536,301			(7,818	)		(17,478	)
Cash, cash equivalents and restricted cash – beginning of period		93,035			100,853			118,331
Cash, cash equivalents and restricted cash – end of period	$	629,336		$	93,035		$	100,853

Supplemental disclosure of non-cash investing and financing activities:
Changes in accounts payable and accrued liabilities associated with construction in progress and property, plant and equipment additions	$	(12,786	)	$	(48,150	)	$	74,280
Cash paid for interest, net of capitalized interest		27,255			6,765			7,515
Cash paid for taxes		58			28			-

The accompanying notes are an integral part of these consolidated financial statements.

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Table of Contents

1.	Organization

New Fortress Energy Inc. (“NFE,” together with its subsidiaries, the “Company”) is a Delaware corporation formed by New Fortress Energy Holdings LLC (“New Fortress Energy Holdings”). The Company is a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs and is engaged in providing energy and development services to end-users worldwide seeking to convert their operating assets from diesel or heavy fuel oil to LNG. The Company currently sources LNG from a combination of its own liquefaction facility in Miami, Florida and purchases on the open market. The Company has liquefaction, regasification and power generation operations in the United States and Jamaica.

The Company manages, analyzes and reports on its business and results of operations on the basis of one operating segment. The chief operating decision maker makes resource allocation decisions and assesses performance based on financial information presented on a consolidated basis.

2.	Significant accounting policies

The principle accounting policies adopted are set out below.

(a)	Basis of presentation and principles of consolidation

The accompanying consolidated financial statements contained herein were prepared in accordance with GAAP. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned consolidated subsidiaries. The ownership interest of other investors in consolidated subsidiaries is recorded as a non-controlling interest. All significant intercompany transactions and balances have been eliminated on consolidation. Certain prior year amounts have been reclassified to conform to current year presentation.

On February 4, 2019, the Company completed an initial public offering (“IPO”) and a series of other transactions, in which the Company issued and sold 20,000,000 Class A shares at an IPO price of $14.00 per share. The Company’s Class A shares began trading on NASDAQ Global Select Market (“NASDAQ”) under the symbol “NFE” on January 31, 2019. Net proceeds from the IPO were $257.0 million, after deducting underwriting discounts and commissions and transaction costs. These proceeds were contributed to New Fortress Intermediate LLC (“NFI”), an entity formed in conjunction with the IPO, in exchange for 20,000,000 limited liability company units in NFI (“NFI LLC Units”). In addition, New Fortress Energy Holdings contributed all of its interests in consolidated subsidiaries that comprised substantially all of its historical operations to NFI in exchange for NFI LLC Units. In connection with the IPO, New Fortress Energy Holdings also received 147,058,824 Class B shares of NFE, which is equal to the number of NFI LLC Units held by New Fortress Energy Holdings immediately following the IPO. New Fortress Energy Holdings retained a significant interest in NFE through its ownership of 147,058,824 Class B shares, representing an 88.0% voting and non-economic interest. New Fortress Energy Holdings also had an 88.0% economic interest in NFI through its ownership of 147,058,824 of NFI LLC Units. New Fortress Energy Holdings is NFE’s predecessor for accounting purposes.

On March 1, 2019, the underwriters of the IPO exercised their option to purchase an additional 837,272 Class A shares at the IPO price of $14.00 per share, less underwriting discounts, which resulted in $11.0 million in additional net proceeds after deducting $0.7 million of underwriting discounts and commissions, such that there were 20,837,272 outstanding Class A shares. In connection with the exercise of the underwriters’ option to purchase an additional 837,272 Class A shares, NFE contributed such additional net proceeds to NFI in exchange for 837,272 NFI LLC Units.

Until the Exchange Transactions (as defined below) were completed, NFE was a holding company whose sole material asset was a controlling equity interest in NFI. As the sole managing member of NFI, NFE operated and controlled all of the business and affairs of NFI, and through NFI and its subsidiaries, conducted the Company’s historical business. The contribution of the assets of New Fortress Energy Holdings and net proceeds from the IPO to NFI was treated as a reorganization of entities under common control (the “Reorganization”). As a result, NFE presented the consolidated balance sheets and statements of operations and comprehensive loss of New Fortress Energy Holdings for all periods prior to the IPO.

On June 3, 2020, the Company entered into a mutual agreement (the “Mutual Agreement”) with the members holding the majority voting interest in New Fortress Energy Holdings (“Exchanging Members”) and NFE Sub LLC, a wholly-owned subsidiary of NFE. Pursuant to the Mutual Agreement, the Exchanging Members agreed to deliver a block redemption notice in accordance with the Amended and Restated Limited Liability Company Agreement of NFI (the “NFI LLCA”) with respect to all of the NFI LLC Units, together with an equal number of Class B shares of NFE, that such Exchanging Members indirectly own as members of New Fortress Energy Holdings. Pursuant to the Mutual Agreement, NFE agreed to exercise the Call Right (as defined in the NFI LLCA), pursuant to which NFE would acquire such NFI LLC Units and such Class B shares in exchange for Class A shares of NFE (the “Exchange Transactions”). The Exchange Transactions were completed on June 10, 2020. In connection with the closing of the Exchange Transactions, NFE issued 144,342,572 Class A shares in exchange for an equal number of NFI LLC Units, together with an equal number of Class B shares of NFE. Following the completion of the Exchange Transactions, NFE owns all of the NFI LLC Units directly or indirectly and no Class B shares remain outstanding.

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Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s consolidated financial statements. Results of operations for the period prior to the date of the Exchange Transactions, June 10, 2020, was attributed to non-controlling interest based on the Exchanging Members’ interest in NFI; subsequent to the Exchange Transactions, results of operations, excluding results attributable to other investors in non-wholly owned subsidiaries, were recognized as net income or loss attributable to stockholders. Amounts that were attributable to these Exchanging Members’ prior interest in NFI previously shown as non-controlling interest on the Company’s consolidated balance sheets have been reclassified to Class A shares.

On August 7, 2020, the Company converted New Fortress Energy LLC (“NFE LLC”) from a Delaware limited liability company to a Delaware corporation named New Fortress Energy Inc. (“the Conversion”). Since the IPO, NFE LLC has been a corporation for U.S. federal tax purposes and converting NFE LLC from a limited liability company to a corporation has no effect on the U.S. federal tax treatment of the Company or its shareholders. Upon the Conversion, each Class A share, representing Class A limited liability company interests of NFE LLC (“Class A shares”), outstanding immediately prior to the Conversion was converted into one issued and outstanding, fully paid and nonassessable share of Class A common stock, $0.01 par value per share, of NFE (“Class A common stock”). Class A shares shown on the Company’s consolidated statements of changes in stockholders’ equity were reclassified to Class A common stock and Additional paid-in capital with no change to total stockholders’ equity. As of December 31, 2020, NFE had 174,622,862 Class A common stock outstanding.

(b)	Use of estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include relative fair value allocations between revenue and lease components of contracts with customers, determination of current expected credit losses, the incremental borrowing rates used in the determination of lease liabilities, total consideration and fair value of identifiable net assets related to acquisitions and the fair value of equity awards granted to both employees and non-employees. Management evaluates its estimates and related assumptions regularly. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

(c)	Foreign currencies

The Company has certain foreign subsidiaries where the functional currency is the local currency. All of the assets and liabilities of these subsidiaries are translated to U.S. dollars at the exchange rate in effect at the balance sheet date; income and expense accounts are translated at average rates for the period. The effects of translating financial statements of foreign operations into our reporting currency are recognized as a cumulative translation adjustment in accumulated other comprehensive income (loss).

The Company also has foreign subsidiaries that have a functional currency of the U.S. dollar. Purchases and sales of assets and income and expense items denominated in foreign currencies are remeasured into U.S. dollar amounts on the respective dates of such transactions. Net realized foreign currency gains or losses relating to the differences between these recorded amounts and the U.S. dollar equivalent actually received or paid are included within Other expense (income), net in the consolidated statements of operations and comprehensive loss. Gains and losses on intercompany foreign currency transactions that are long-term in nature and which the Company does not intend to settle in the foreseeable future, are also recognized in accumulated other comprehensive income (loss). Accumulated foreign currency translation adjustments are reclassified from accumulated other comprehensive income (loss) to net income only when realized upon sale or upon complete or substantially complete liquidation of the investment in a foreign entity. If the Company commits to a plan to sell or liquidate a foreign entity, accumulated foreign currency translation adjustments would be included in carrying amounts in impairment assessments.

(d)	Cash and cash equivalents

The Company considers all highly liquid investments with an original maturity of three months or less at the time of purchase to be cash equivalents.

(e)	Restricted cash

Restricted cash consists of funds that are contractually restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on the consolidated balance sheets.

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(f)	Receivables

Receivables are reported at amortized cost, net of an allowance for current expected credit losses. Amounts are written off against the allowance when management is certain that outstanding amounts will not be collected. The Company estimates expected credit losses based on relevant information about the current credit quality of customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectability of the reported amount. Credit loss expense, inclusive of credit loss expense on all categories of financial assets, is recorded within Selling, general and administrative in the consolidated statements of operations and comprehensive loss.

(g)	Inventories

LNG and natural gas inventories and automotive diesel oil inventories are recorded at weighted average cost, and materials and other inventory are recorded at cost. The Company’s cost to convert from natural gas to LNG, which primarily consists of labor, depreciation and other direct costs to operate liquefaction facilities, is reflected in Inventory on the consolidated balance sheets.

LNG is subject to “boil-off,” a natural loss of gas volume over time when LNG is exposed to environments with temperatures above its optimum storage state. Boil-off losses are expensed through Cost of sales in the consolidated statements of operations and comprehensive loss in instances where gas cannot be contained and recycled back into the production process.

(h)	Construction in progress

Construction in progress is recorded at cost, and at the point at which the constructed asset is put into use, the full cost of the asset is reclassified from Construction in progress to Property, plant and equipment, net or Finance leases, net on the consolidated balance sheets. Construction progress payments, engineering costs and other costs directly relating to the asset under construction are capitalized during the construction period, provided the completion of the construction project is deemed probable or if the costs are associated with activities that could be utilized in future projects. Depreciation is not recognized during the construction period.

The interest cost associated with major development and construction projects is capitalized during the construction period and included in the cost of the project in Construction in progress.

(i)	Property, plant and equipment, net

Property, plant and equipment is recorded at cost. Expenditures for construction activities and betterments that extend the useful life of the asset are capitalized. Major maintenance and overhauls are capitalized and depreciated over the expected period until the next anticipated major maintenance or overhaul, while expenditures for routine maintenance and repairs are charged to expense as incurred within Operations and maintenance in the consolidated statements of operations and comprehensive loss. The Company depreciates property, plant and equipment using the straight-line depreciation method over the estimated economic life of the asset or lease term, whichever is shorter using the following useful lives:

	Useful life (Yrs)
Terminal and power plant equipment	4-24
CHP facilities	4-20
Gas terminals	5-24
ISO containers and other equipment	3-25
LNG liquefaction facilities	20-40
Gas pipelines	4-24
Leasehold improvements	2-20

The Company reviews the remaining useful life of its assets on a regular basis to determine whether changes have taken place that would suggest that a change to depreciation policies is warranted.

Upon retirement or disposal of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses, if any, are recorded in the consolidated statements of operations and comprehensive loss.

(j)	Asset retirement obligations (“AROs”)

AROs are recognized for legal obligations associated with the retirement of long-lived assets that result from the acquisition, leasing, construction, development and/or normal use of the assets and for conditional AROs in which the timing or method of settlement are conditional on a future event. The fair value of a liability for an ARO is recognized in the period in which the liability is incurred if a reasonable estimate of fair value can be made and is accreted to its final value over the life of the liability. The initial fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

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The Company estimates the fair value of the ARO liability based on the present value of expected cash flows using a credit-adjusted risk-free rate. Liabilities for AROs may be incurred over more than one reporting period if the events that create the obligation occur over more than one period or if estimates change. The liability is accreted to its present value each period and the capitalized cost is depreciated in Depreciation and amortization in the consolidated statements of operations and comprehensive loss. Upon settlement of the obligation, the Company eliminates the liability and based on the actual cost to retire, may incur a gain or loss. There were no settlements of AROs during the years ended December 31, 2020 and 2019.

(k)	Impairment of long-lived assets

The Company performs a recoverability assessment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Indicators may include, but are not limited to, adverse changes in the regulatory environment in a jurisdiction where the Company operates, unfavorable events impacting the supply chain for LNG to the Company’s operations, a decision to discontinue the development of a long-lived asset, early termination of a significant customer contract or the introduction of newer technology.

Management develops the assumptions used in the recoverability assessment based on active contracts, current and future expectations of the global demand for LNG and natural gas, as well as information received from third party industry sources. The Company did not record an impairment during the years ended December 31, 2020, 2019 and 2018.

(l)	Investment in equity securities

Investment in equity securities is carried at fair value and included in Other non-current assets on the consolidated balance sheets, with gains or losses recorded in earnings in Other expense (income), net in the consolidated statements of operations and comprehensive loss.

(m)	Intangible assets

Upon a business combination or asset acquisition, the Company may obtain identifiable intangible assets. Intangible assets with a finite life are amortized over the estimated useful life of the asset under the straight-line method.

Indefinite lived intangible assets are not amortized. Intangible assets with an indefinite useful life are tested for impairment on an annual basis or more frequently if changes in circumstances indicate that it is more likely than not that the asset is impaired. Indefinite lived intangible assets are evaluated for impairment either under the qualitative assessment option or the two-step quantitative test. If the carrying amount of an intangible asset being tested for impairment exceeds its fair value, the excess is recognized as impairment expense in the consolidated statements of operations and comprehensive loss.

(n)	Long-term debt and debt issuance costs

The Company’s debt has historically consisted of credit facilities with financial institutions and secured and unsecured bonds. Costs directly related to the issuance of debt are reported on the consolidated balance sheets as a reduction from the carrying amount of the recognized debt liability and amortized over the term of the debt using the effective interest method. Interest and related amortization of debt issuance costs recognized during major development and construction projects are capitalized and included in the cost of the project.

(o)	Contingencies

The Company may be involved in legal actions in the ordinary course of business, including governmental and administrative investigations, inquiries and proceedings concerning employment, labor, environmental and other claims. The Company will recognize a loss contingency in the consolidated financial statements when it is probable a liability has been incurred and the amount of the loss can be reasonably estimated. The Company will disclose any loss contingencies that do not meet both conditions if there is a reasonable possibility that a loss may have been incurred. Gain contingencies are not recorded until realized.

(p)	Revenue recognition

The Company’s 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 the Company’s natural gas-fueled infrastructure. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. The customers consume the benefit of the natural gas, power and steam when they are delivered by the Company to the customer’s power generation facilities or interconnection facility. Natural gas, power and steam qualify as a series with revenue being recognized over time using an output method, based on the quantity of natural gas, power or steam that the customer has consumed. LNG is typically delivered in containers transported by truck to customer sites. Revenue from sales of LNG delivered by truck is recognized at the point in time at which physical possession and the risks and rewards of ownership transfer to the customer, either when the containers are shipped or delivered to the customers’ storage facilities, depending on the terms of the contract. Because the nature, timing and uncertainty of revenue and cash flows are substantially the same for LNG, natural gas, power and steam, the Company has presented Operating revenue on an aggregated basis. The Company has concluded that variable consideration included in its agreements meets the exception for allocating variable consideration. As such, the variable consideration for these contracts is allocated to each distinct unit of LNG, natural gas, power or steam delivered and recognized when that distinct unit is delivered to the customer.

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The Company’s contracts with customers to supply natural gas or LNG may contain a lease of equipment. The Company allocates consideration received from customers between lease and non-lease components based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone selling price of the same or similar equipment leased to the customer. The Company estimates the fair value of the non-lease component by forecasting volumes and pricing of gas to be delivered to the customer over the lease term.

The leases of certain facilities and equipment to customers are accounted for as finance or operating leases. The current and non-current portion of finance leases are recorded within Prepaid expenses and other current assets and Finance leases, net on the consolidated balance sheets, respectively. For finance leases accounted for as sales-type leases, the profit from the sale of equipment is recognized upon lease commencement in Other revenue in the consolidated statements of operations and comprehensive loss. The lease payments for finance leases are segregated into principal and interest components similar to a loan. Interest income is recognized on an effective interest method over the lease term and included in Other revenue in the consolidated statements of operations and comprehensive loss. The principal component of the lease payment is reflected as a reduction to the net investment in the lease. For the Company’s operating leases, the amount allocated to the leasing component is recognized over the lease term as Other revenue in the consolidated statements of operations and comprehensive loss.

In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes revenue recognized from the construction, installation and commissioning of equipment, inclusive of natural gas delivered for the commissioning process, to transform customers’ facilities to operate utilizing natural gas or to allow customers to receive power or other outputs from our natural gas-fueled power generation facilities. Revenue from these development services is recognized over time as the Company transfers control of the asset to the customer or based on the quantity of natural gas consumed as part of commissioning the customer’s facilities until such time that the customer has declared such conversion services have been completed. If the customer is not able to obtain control over the asset under construction until such services are completed, revenue is recognized when the services are completed and the customer has control of the infrastructure. Such agreements may also include a significant financing component, and the Company recognizes revenue for the interest income component over the term of the financing as Other revenue.

The timing of revenue recognition, billings and cash collections results in receivables, contract assets and contract liabilities. Receivables represent unconditional rights to consideration; unbilled amounts typically result from sales under long-term contracts when revenue recognized exceeds the amount billed to the customer. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. Both unbilled receivables and contract assets are recognized within Prepaid expenses and other current assets, net and Other non-current assets, net on the consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the consolidated balance sheets.

Shipping and handling costs are not considered to be separate performance obligations. These costs are recognized in the period in which the costs are incurred and presented within Cost of sales in the consolidated statements of operations and comprehensive loss. All such shipping and handling activities are performed prior to the customer obtaining control of the LNG or natural gas.

The Company collects sales taxes from its customers based on sales of taxable products and remits such collections to the appropriate taxing authority. The Company has elected to present sales tax collections in the consolidated statements of operations and comprehensive loss on a net basis and, accordingly, such taxes are excluded from reported revenues.

The Company elected the practical expedient under which the Company does not adjust consideration for the effects of a significant financing component for those contracts where the Company expects at contract inception that the period between transferring goods to the customer and receiving payment from the customer will be one year or less.

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(q)	Contract termination charges and loss on mitigation sales

The Company has long-term supply agreements to purchase LNG, and the Company may incur termination charges to the extent that the Company cancels such contractual arrangements. Further, if the Company is unable to take physical possession of a portion of the contracted quantity of LNG due to capacity limitations, the supplier will attempt to sell the undelivered quantity through a mitigation sale. The Company may incur a loss on a mitigation sale if the cargo is unable to be sold for a price greater than the contracted price. These costs are included in a separate line in the consolidated statements of operations and comprehensive loss because such costs are not related to inventory delivered to the Company’s customers.

During the year ended December 31, 2020, the Company recognized a termination charge of $105,000 associated with an agreement with one of the Company’s LNG suppliers to terminate the obligation to purchase any LNG from this supplier for the remainder of 2020. Loss on mitigation sales of $19,114 were recognized during the year ended December 31, 2020.

(r)	Leases, as lessee

Effective January 1, 2020, the Company adopted ASU 2016-02, Leases (Topic 842), using a modified retrospective approach. The Company has entered into lease agreements for the use of LNG vessels, marine port space, office space, land and equipment, all of which are operating leases. Right-of-use (“ROU”) assets recognized for these leases represent the Company’s right to use an underlying asset for the lease term, and the lease liabilities represent the Company’s obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the estimated present value of fixed lease payments over the lease term.

Leases with terms of 12 months or less are excluded from ROU assets and lease liabilities on the balance sheet, and short-term lease payments are recognized on a straight-line basis over the lease term. Variable payments under short-term leases are recognized in the period in which the obligation that triggers the variable payment becomes probable.

The Company, as lessee, has also elected the practical expedient not to separate lease and non-lease components for marine port space, office space, land and equipment leases. The Company separates the lease and non-lease components for LNG vessel leases. The allocation of lease payments between lease and non-lease components has been determined based on the relative fair value of each component. The fair value of the lease component is estimated based on the estimated standalone price to lease a bareboat LNG vessel. The fair value of the non-lease component is estimated based on the estimated standalone price of operating the respective vessel, inclusive of the costs of the crew and other operating costs.

The Company has elected the land easement practical expedient, which allows the Company to continue to account for pre-existing land easements as intangible assets under the accounting policy that existed before adoption of ASC 842.

(s)	Share-based compensation

In connection with the IPO, the Company adopted the New Fortress Energy LLC 2019 Omnibus Incentive Plan (the “Incentive Plan”), effective as of February 4, 2019. Under the Incentive Plan, the Company may issue options, share appreciation rights, restricted shares, restricted share units (“RSUs”), share bonuses or other share-based awards to selected officers, employees, non-employee directors and select non-employees of NFE or its affiliates. The Company accounts for share-based compensation in accordance with ASC 718, Compensation – Stock Compensation, and ASC 505, Equity, which require all share-based payments to employees and members of the board of directors to be recognized as expense in the consolidated financial statements based on their grant date fair values. The Company has elected not to estimate forfeitures of its share-based compensation awards but recognizes the reversal in compensation expense in the period in which the forfeiture occurs.

During the first quarter of 2020, the Company granted performance share units (“PSUs”) to certain employees and non-employees. The PSUs contain a performance condition, and vesting will be determined based on achievement of an adjusted operating margin for the year ended December 31, 2021.

(t)

Taxation

Federal and state income taxes

The Company accounts for income taxes in accordance with ASC 740, “Accounting for Income Taxes” (“ASC 740”), under which deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts and the tax bases of assets and liabilities by applying the enacted tax rates in effect for the year in which the differences are expected to reverse. Such net tax effects on temporary differences are reflected on the Company’s consolidated balance sheets as deferred tax assets and liabilities. Deferred tax assets are reduced by a valuation allowance when the Company believes that it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized.

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The Company recognizes the effect of tax positions only if those positions are more likely than not of being sustained. Recognized tax positions are measured at the largest amount that is greater than 50 percent likely of being realized. Conclusions reached regarding tax positions are continually reviewed based on ongoing analyses of tax laws, regulations and interpretations thereof. To the extent that the Company’s assessment of the conclusions reached regarding tax positions changes as a result of the evaluation of new information, such change in estimate will be recorded in the period in which such determination is made. The Company reports interest and penalties relating to an underpayment of income taxes, if applicable, as a component of income tax expense.

The Company has elected to treat amounts incurred under the global intangible low-taxed income (“GILTI”) rules as an expense in the period in which the tax is accrued. Accordingly, no deferred tax assets or liabilities are recorded related to GILTI.

Foreign taxes

Certain subsidiaries of the Company are subject to income tax in the local jurisdiction in which they operate; foreign taxes are computed based on the taxable income and the local jurisdictional tax rate.

Other taxes

Certain subsidiaries may be subject to payroll taxes, excise taxes, property taxes, sales and use taxes, in addition to income taxes in foreign countries in which they conduct business. In addition, certain subsidiaries are exposed to local state taxes, such as franchise taxes. Local state taxes that are not income taxes are recorded within Other expense (income), net in the consolidated statements of operations and comprehensive loss.

(u)	Net loss per share

Basic net loss per share (“EPS”) is computed by dividing net loss attributable to Class A common stock by the weighted average number of shares of Class A common stock outstanding during the period following the Reorganization. Class B shares represented non-economic interests in the Company, and as such, prior to the Exchange Transactions, earnings were not allocated to Class B shares.

The dilutive effect of outstanding awards, if any, is reflected in diluted earnings per share by application of the treasury stock method or if-converted method, as applicable. For the years ended December 31, 2020 and 2019, there were no potentially dilutive shares outstanding.

3.	Adoption of new and revised standards

Following the issuance of Senior Secured Notes (defined below) on September 2, 2020, the Company ceased to qualify as an “emerging growth company” or EGC and is required to accelerate the adoption of certain new or revised accounting pronouncements. The adoption dates below reflect the changes as a result of no longer qualifying as an EGC.

(a)	New standards, amendments and interpretations issued but not effective for the financial year beginning January 1, 2020:

In December 2019, the Financial Accounting Standards Board (“FASB”) issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes, including removing certain exceptions related to the general principles in ASU 740, Income Taxes. ASU 2019-12 also clarifies and simplifies other aspects of the accounting for income taxes. The new standard is effective for interim and annual periods beginning after December 15, 2020, and early adoption is permitted. The Company will adopt ASC 2019-12 in the first quarter of 2021 and does not expect the adoption of this new standard to materially impact the Company’s financial position, results of operations or cash flows.

In August 2020, the FASB issued ASU 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. ASU 2020-06 requires entities to provide expanded disclosures about the terms and features of convertible instruments and amends certain guidance in ASC 260 on the computation of EPS for convertible instruments and contracts on an entity’s own equity. ASU 2020-06 is effective for public companies for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years, with early adoption of all amendments in the same period permitted. The Company is currently assessing the impact of adoption of this guidance.

(b)	New and amended standards adopted by the Company:

In June 2016, the FASB issued 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, including trade receivables, to be presented net of the amount expected to be collected. The measurement of all expected credit losses will be based on relevant information about the credit quality of customers, past events, including historical experience, and reasonable and supportable forecasts that affect the collectability of the reported amount. Upon the loss of EGC status, ASU 2016-13 was adopted in the third quarter of 2020 with an effective date of January 1, 2020. The Company elected to apply the modified retrospective transition method, which allowed the Company to begin recognizing and measuring current expected credit losses at January 1, 2020, without modifying the comparative period financial statements. In connection with the adoption of ASC 2016-13, the Company recorded a transition adjustment of $228 which was recorded as an adjustment to retained earnings. The Company recorded credit loss expense of $316 for the year ended December 31, 2020.

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On February 25, 2016, the FASB issued ASU No. 2016-02, Leases (“ASC 842”), which amended the existing accounting standards for lease accounting, including requiring most leases to be recognized on a lessee’s balance sheet and making targeted changes to lessor accounting. The recognition, measurement and presentation of expenses and cash flows arising from a lease by a lessee will depend primarily on the lease’s classification as a finance or operating lease. However, unlike ASC 840, which required only capital leases to be recognized on the balance sheet, ASC 842 requires most leases to be recognized on the balance sheet as a ROU asset and a lease liability.

The Company adopted ASC 842 effective January 1, 2020 and elected to apply the modified retrospective transition method at the beginning of the period of adoption, which allowed the Company to begin recognizing and measuring leases under ASC 842 at January 1, 2020, without modifying the comparative period financial statements. Upon adoption of ASC 842, the Company recorded ROU assets and corresponding lease liabilities of $124,774 and $103,874, respectively.

The Company did not elect the package of practical expedients and therefore, as part of transition, the Company reassessed the previous conclusions made under ASC 840 related to the identification of leases, classification of leases and initial direct costs based on the standards of ASC 842. In connection with the reassessment of previous conclusions, the Company determined that the direct financing lease recognized related to the Montego Bay Facility is no longer a lease under ASC 842. The Company recognized a transition adjustment that removed the unamortized net investment in the direct financing lease and recognized the underlying assets as Property, plant and equipment, net of depreciation, that would have been recognized since the commissioning of the Montego Bay Facility, with the difference of approximately $9,085, net of taxes of $2,945, recorded as a reduction to retained earnings. Beginning in 2020, the Company recognized payments previously allocated to the leasing component of the gas sales agreement with this customer within Operating revenue in the consolidated statements of operations and comprehensive loss. Under ASC 840, amounts allocated to the leasing component had been recognized on an effective interest method over the lease term with only the portion representing interest income recognized as Other revenue.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which provides additional guidance to improve the effectiveness of disclosure requirements on fair value measurement. The Company has adopted ASU 2018-13 for the year beginning January 1, 2020. As this guidance is only related to qualitative financial disclosures, it did not have a material impact on the Company’s consolidated financial statements.

In August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which requires a customer in a cloud computing arrangement that is a service contract to follow the internal-use software guidance in ASC 350-40 to determine which implementation costs to capitalize as assets. A customer’s accounting for the costs of the hosting component of the arrangement is not affected by the new guidance. The Company has early adopted ASU 2018-15 for the year beginning January 1, 2020, using the prospective transition approach. This approach did not require any adjustment to comparative financial statements. The Company has not capitalized a significant amount of implementation costs as a result of adopting this guidance in the year ended December 31, 2020, and the adoption did not result in material impact on the Company’s consolidated financial statements.

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The guidance provides temporary optional expedients and exceptions to the current guidance on contract modifications and hedge accounting to ease the financial reporting burdens related to the expected market transition from the London Interbank Offered Rate (“LIBOR”) and other interbank offered rates to alternative reference rates. The guidance was effective upon issuance and generally can be applied to applicable contract modifications and hedge relationships prospectively through December 31, 2022. The adoption of this guidance did not have a significant impact on the Company’s financial statements.

4.	Revenue from contracts with customers

Under most customer contracts, invoicing occurs once the Company’s performance obligations have been satisfied, at which point payment is unconditional. As of December 31, 2020 and 2019, receivables related to revenue from contracts with customers totaled $76,431 and $40,731, respectively, and were included in Receivables, net on the consolidated balance sheets, net of current expected credit losses of $98 and $0, respectively. Other items included in Receivables, net not related to revenue from contracts with customers represent receivables associated with reimbursable costs and leases which are accounted for outside the scope of ASC 606.

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The Company has recognized contract liabilities, comprised of unconditional payments due or paid under the contracts with customers prior to the Company’s satisfaction of the related performance obligations. The performance obligations are expected to be satisfied during the next 12 months, and the contract liabilities are classified within Other current liabilities on the consolidated balance sheets. Contract assets are comprised of the transaction price allocated to completed performance obligations that will be billed to customers in subsequent periods. The contract liabilities and contract assets balances as of December 31, 2020 and 2019 are detailed below:

	December 31, 2020		December 31, 2019
Contract assets, net - current	$	3,673	$	3,787
Contract assets, net - non-current		23,972		19,474
Total contract assets, net	$	27,645	$	23,261

Contract liabilities	$	8,399	$	6,542

Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year	$	6,542	$	-

Contract assets are presented net of expected credit losses of $372 and $0 as of December 31, 2020 and 2019, respectively. As of December 31, 2020, the Company has unbilled receivables, net of current expected credit losses, of $6,818, of which $356 is presented within Other current assets and $6,462 is presented within Other non-current assets on the consolidated balance sheets. These unbilled receivables represent unconditional right to payment subject only to the passage of time.

Operating revenue which includes revenue from sales of LNG and natural gas as well as outputs from the Company’s natural gas-fueled power generation facilities, including power and steam, was $318,311, $145,500 and $96,906 for the years ended December 31, 2020, 2019 and 2018 respectively. During March 2020, the Company began to deliver power and steam recognizing $23,062 in operating revenue for the year ended December 31, 2020.

Other revenue includes revenue for development services as well as lease and other revenue. The table below summarizes the balances in Other revenue:

	Year Ended December 31,
	2020		2019		2018
Development services revenue	$	129,753	$	27,308	$	-
Lease and other revenue		3,586		16,317		15,395
Total other revenue	$	133,339	$	43,625	$	15,395

Development services revenue recognized in the year ended December 31, 2020 included $118,757 for the customer’s use of natural gas as part of commissioning their assets.

Transaction price allocated to remaining performance obligations

Some of the Company’s contracts are short-term in nature with a contract term of less than a year. The Company applied the optional exemption not to report any unfulfilled performance obligations related to these contracts.

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The Company has arrangements in which LNG, natural gas or outputs from the Company’s power generation facilities are sold on a “take-or-pay” basis whereby the customer is obligated to pay for the minimum guaranteed volumes even if it does not take delivery. The price under these agreements is typically based on a market index plus a fixed margin. The fixed transaction price allocated to the remaining performance obligations under these arrangements is $4,357,054 as of December 31, 2020, representing the fixed margin multiplied by the outstanding minimum guaranteed volumes. The Company expects to recognize this revenue over the following time periods. The pattern of recognition reflects the minimum guaranteed volumes in each period:

Period	Revenue
2021	$	258,738
2022		250,226
2023		250,317
2024		249,804
2025		246,709
Thereafter		3,101,260
Total	$	4,357,054

For all other sales contracts that have a term exceeding one year, the Company has elected the practical expedient in ASC 606 under which the Company does not disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. For these excluded contracts, the sources of variability are (a) the market index prices of natural gas used to price the contracts, and (b) the variation in volumes that may be delivered to the customer. Both sources of variability are expected to be resolved at or shortly before delivery of each unit of LNG, natural gas, power or steam. As each unit of LNG, natural gas, power or steam represents a separate performance obligation, future volumes are wholly unsatisfied.

The Company has recognized costs to fulfill a contract with a significant customer, which primarily consist of expenses required to enhance resources to deliver under the agreement with the customer. As of December 31, 2020, the Company has capitalized $11,276, of which $588 of these costs is presented within Other current assets and $10,688 is presented within Other non-current assets on the consolidated balance sheets. As of December 31, 2019, the Company had capitalized $8,839, of which $331 of these costs was presented within Other current assets and $8,508 was presented within Other non-current assets on the consolidated balance sheets. In the first quarter of 2020, the Company began delivery under the agreement and started recognizing these costs on a straight-line basis over the expected term of the agreement.

Leases

The Company has operating leases primarily for the use of LNG vessels, marine port space, office space, land and equipment under non-cancellable lease agreements. The Company’s leases may include multiple optional renewal periods that are exercisable solely at the Company’s discretion. Renewal periods are included in the lease term when the Company is reasonably certain that the renewal options would be exercised, and the associated lease payments for such periods are reflected in the ROU asset and lease liability.

The Company’s leases include fixed lease payments which may include escalation terms based on a fixed percentage or may vary based on an inflation index or other market adjustments. Escalations based on changes in inflation indices and market adjustments and other lease costs that vary based on the use of the underlying asset are not included as lease payments in the calculation of the lease liability or ROU asset; such payments are included in variable lease cost when the obligation that triggers the variable payment becomes probable. Variable lease cost includes contingent rent payments for office space based on the percentage occupied by the Company in addition to common area charges and other charges that are variable in nature. The Company also has a component of lease payments that are variable related to the LNG vessels, in which the Company may receive credits based on the performance of the LNG vessels during the period.

For the year ended December 31, 2020, the Company’s operating lease cost recorded within the consolidated statements of operations and comprehensive loss were as follows:

	December 31, 2020
Fixed lease cost	$	39,841
Variable lease cost		2,013
Short-term lease cost		1,454

Lease cost - Cost of sales	$	36,283
Lease cost - Operations and maintenance		2,501
Lease cost - Selling, general and administrative		4,524

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For the year ended December 31, 2020, the Company has capitalized $10,457 of lease costs for vessels and port space used during the commissioning of development projects in addition to short-term lease costs for vessels chartered by the Company to bring inventory from a supplier’s facilities to the Company’s storage locations which are capitalized to inventory.

Cash paid for operating leases is reported in operating activities in the consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the year ended December 31, 2020:

	December 31, 2020
Operating cash outflows for operating lease liabilities	$	45,934
Right-of-use assets obtained in exchange for new operating lease liabilities		182,799

The future payments due under operating leases as of December 31, 2020 are as follows:

	Operating Leases
2021	$	43,467
2022		29,949
2023		18,738
2024		17,884
2025		10,698
Thereafter		50,387
Total lease payments	$	171,123
Less: effects of discounting		51,319
Present value of lease liabilities	$	119,804

Current lease liability	$	35,481
Non-current lease liability		84,323

As of December 31, 2020, the weighted-average remaining lease term for all operating leases was 7.2 years. Because the Company generally does not have access to the rate implicit in the lease, the incremental borrowing rate is utilized as the discount rate. The weighted average discount rate associated with operating leases as of December 31, 2020 was 8.3%.

Future annual minimum lease payments for operating leases as of December 31, 2019, prepared in accordance with accounting standards prior to the adoption of ASC 842, were as follows:

Year ending December 31:
2020	$	37,776
2021		35,478
2022		18,387
2023		7,083
2024		7,151
Thereafter		26,458
Total	$	132,333

During the years ended December 31, 2019 and 2018, the Company recognized rental expense for all operating leases of $37,069 and $23,687, respectively, related primarily to LNG vessel time charters, office space, a land site lease and marine port berth leases.

The Company has entered into several leases for ISO tanks that have not commenced as of December 31, 2020 with noncancelable terms of 5 years and including fixed payments of approximately $19 million.

Lessor

In the Company’s agreements to sell LNG or natural gas to customers, the Company may also lease certain equipment to customers which are accounted for either as a finance or an operating lease. Property, plant and equipment subject to operating leases is included within ISO containers and other equipment within Note 11. Property, plant and equipment, net. The following is the amount of property, plant and equipment that is leased to customers:

	December 31, 2020
Property, plant and equipment	$	18,394
Accumulated depreciation		(932	)
Property, plant and equipment, net	$	17,462

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The following table shows the expected future lease payments as of December 31, 2020, for 2021 through 2025 and thereafter:

	Future cash receipts
	Financing leases		Operating leases
2021	$	1,965	$	256
2022		2,065		247
2023		2,066		249
2024		2,068		234
2025		1,933		194
Thereafter		5,438		539
Total	$	15,535	$	1,719
Less: Imputed interest		7,119
Present value of total lease receipts	$	8,416

Current finance leases, net	$	1,372
Non-current finance leases, net		7,044

6.	Fair value

Fair value measurements and disclosures require the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize use of unobservable inputs. These inputs are prioritized as follows:

•	Level 1 – observable inputs such as quoted prices in active markets for identical assets or liabilities.

•	Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities or market corroborated inputs.

•	Level 3 – unobservable inputs for which there is little or no market data and which require the Company to develop its own assumptions about how market participants price the asset or liability.

The valuation techniques that may be used to measure fair value are as follows:

•	Market approach – uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•	Income approach – uses valuation techniques, such as the discounted cash flow technique, to convert future amounts to a single present amount based on current market expectations about those future amounts.

•	Cost approach – based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

The following table presents the Company’s financial assets and financial liabilities that are measured at fair value as of December 31, 2020 and 2019:

	December 31, 2020
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets										0
Cash and cash equivalents	$	601,522	$	-	$	-	$	601,522	Market approach
Restricted cash		27,814		-		-		27,814	Market approach
Investment in equity securities		1,095		-		-		1,095	Market approach
Total	$	630,431	$	-	$	-	$	630,431

Liabilities
Derivative liability¹	$	-	$	-	$	10,716	$	10,716	Income approach
Equity agreement²		-		-		22,768		22,768	Income approach
Total	$	-	$	-	$	33,484	$	33,484

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	December 31, 2019
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets										0
Cash and cash equivalents	$	27,098	$	-	$	-	$	27,098	Market approach
Restricted cash		65,937		-		-		65,937	Market approach
Investment in equity securities		2,540		-		-		2,540	Market approach
Total	$	95,575	$	-	$	-	$	95,575

Liabilities
Derivative liability¹	$	-	$	-	$	9,800	$	9,800	Income approach
Equity agreement²		-		-		16,800		16,800	Income approach
Total	$	-	$	-	$	26,600	$	26,600

⁽¹⁾	Consideration due to the sellers of Shannon LNG once first gas is supplied from the terminal to be built.

⁽²⁾	To be paid at the earlier of agreed-upon date or the date on which the valid planning permission is received as specified in the amended Shannon LNG Agreement.

The Company estimates fair value of the derivative liability and equity agreement using a discounted cash flows method with discount rates based on the average yield curve for bonds with similar credit ratings and matching terms to the discount periods as well as a probability of the contingent event occurring. The table below summarizes the fair value adjustment, recorded within Other expense (income), net in the consolidated statements of operations and comprehensive loss, and currency translation adjustment, recorded within the Other comprehensive loss, for the year ended December 31, 2020 and 2019:

	December 31, 2020		December 31, 2019
Fair value adjustment - Loss	$	4,408	$	121
Currency translation adjustment - Loss/(gain)		2,476		(280	)

During the years ended December 31, 2020 and 2019, the Company had no settlements of the equity agreement or derivative liability or any transfers in or out of Level 3 in the fair value hierarchy.

The liability associated with the equity agreement of $22,768 and $16,800 as of December 31, 2020 and 2019, respectively, is recorded within Other current liabilities on the consolidated balance sheets. The liability associated with the derivative liability of $10,716 and $9,800 as of December 31, 2020 and 2019, respectively, is recorded within Other long-term liabilities on the consolidated balance sheets.

The Company estimates fair value of outstanding debt using quoted market prices. The fair value of the Senior Secured Notes (defined below in “Note 15. Debt”) was approximately $1,327,488 as of December 31, 2020. The fair value estimate is classified as Level 2 in the fair value hierarchy.

7.	Restricted cash

As of December 31, 2020 and 2019, restricted cash consisted of the following:

	December 31, 2020		December 31, 2019
Collateral for performance under customer agreements	$	15,000	$	15,000
Collateral for LNG purchases		11,664		35,000
Collateral for letters of credit and performance bonds		900		7,388
Debt service reserve account		-		8,299
Other restricted cash		250		250
Total restricted cash	$	27,814	$	65,937

Current restricted cash	$	12,814	$	30,966
Non-current restricted cash		15,000		34,971

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Inventory

As of December 31, 2020 and 2019, inventory consisted of the following:

	December 31, 2020		December 31, 2019
LNG and natural gas inventory	$	13,986	$	57,436
Automotive diesel oil inventory		3,986		4,746
Bunker fuel, materials, supplies and other		4,888		1,250
Total inventory	$	22,860	$	63,432

Inventory is adjusted to the lower of cost or net realizable value each quarter. Changes in the value of inventory are recorded within Cost of sales in the consolidated statements of operations and comprehensive loss. The Company recorded an adjustment to the value of inventory of $0, $251 and $0 during the years ended December 31, 2020, 2019 and 2018, respectively.

9.	Prepaid expenses and other current assets

As of December 31, 2020 and 2019, prepaid expenses and other current assets consisted of the following:

	December 31, 2020		December 31, 2019
Prepaid LNG	$	11,987	$	7,097
Prepaid expenses		4,941		7,458
Due from affiliates (Note 21)		1,881		1,577
Other current assets		29,461		23,602
Total prepaid expenses and other current assets, net	$	48,270	$	39,734

Other current assets as of December 31, 2020 and 2019 primarily consists of receivables for recoverable taxes.

10.	Construction in progress

The Company’s construction in progress activity during the years ended December 31, 2020 and 2019 is detailed below:

	December 31, 2020			December 31, 2019
Balance at beginning of period	$	466,587		$	254,700
Additions		118,530			315,188
Transferred to property, plant and equipment, net (Note 11)		(351,080	)		(103,301	)
Balance at end of period	$	234,037		$	466,587

Interest expense of $25,924, $25,172 and $1,732 was capitalized for the years ended December 31, 2020, 2019 and 2018, respectively, inclusive of amortized debt issuance costs disclosed in “Note 15. Debt.”

11.	Property, plant and equipment, net

As of December 31, 2020 and 2019 the Company’s property, plant and equipment, net consisted of the following:

	December 31, 2020			December 31, 2019
Terminal and power plant equipment	$	188,855		$	14,981
CHP facilities		119,723			-
Gas terminals		120,810			53,380
ISO containers and other equipment		100,137			42,704
LNG liquefaction facilities		63,213			62,929
Gas pipelines		58,974			11,684
Land		16,246			15,401
Leasehold improvements		8,723			8,054
Accumulated depreciation		(62,475	)		(16,911	)
Total property, plant and equipment, net	$	614,206		$	192,222

Depreciation for years ended December 31, 2020, 2019 and 2018 totaled $32,116, $7,527 and $3,900, respectively, of which $927, $701 and $713, respectively, is included within Cost of sales in the consolidated statements of operations and comprehensive loss.

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12.	Intangible assets, net

The following table summarizes the composition of intangible assets as of December 31, 2020 and 2019:

	December 31, 2020
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Shannon LNG permits	$	45,897	$	2,438	$	43,459		40
Easements		1,559		190		1,369		30

Indefinite-lived intangible assets
Easements		1,274		-		1,274		n/a
Total intangible assets	$	48,730	$	2,628	$	46,102

	December 31, 2019
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Shannon LNG permits	$	42,157	$	1,198	$	40,959		40
Easements		1,559		139		1,420		30

Indefinite-lived intangible assets
Easements		1,161		-		1,161		n/a
Total intangible assets	$	44,877	$	1,337	$	43,540

As of December 31, 2020 and 2019, the weighted-average remaining amortization periods for the intangible assets was 37.5 years and 38.8 years, respectively. As of January 1, 2020, intangible assets associated with favorable lease terms in acquired leases have been reclassified as ROU assets as a result of adoption of ASC 842.

Amortization for the years ended December 31, 2020 and 2019 totaled $1,120 and $1,114, respectively. The estimated aggregate amortization expense for each of the next five years is:

Year ending December 31:
2021	$	1,199
2022		1,199
2023		1,199
2024		1,199
2025		1,199
Thereafter		38,833
Total	$	44,828

13.	Other non-current assets

As of December 31, 2020 and 2019, other non-current assets consisted of the following:

	December 31, 2020		December 31, 2019
Nonrefundable deposit	$	28,509	$	22,262
Contract asset, net (Note 4)		23,972		19,474
Cost to fulfill (Note 4)		10,688		8,508
Unbilled receivables, net (Note 4)		6,462		-
Upfront payments to customers		6,330		5,904
Port access rights and initial lease costs		-		17,762
Other		10,069		10,256
Total other non-current assets, net	$	86,030	$	84,166

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Nonrefundable deposits are primarily related to deposits for planned land purchases in Pennsylvania and Ireland.

Upfront payments to customers consist of amounts the Company has paid in relation to two natural gas sales contracts with customers to construct fuel-delivery infrastructure that the customers will own.

Other includes upfront payments to our service providers, a long-term refundable deposit and investments in equity securities. During the fourth quarter of 2020, the Company invested $1,000 in a hydrogen technology development company through a Simple Agreement for Future Equity (“SAFE”) that will convert to preferred shares upon completion of a qualified financing by the investee, and this amount is classified within other in the table above.

As of January 1, 2020, port access rights related to the Company’s port lease in Baja California Sur, Mexico, and payments to incumbent tenants to secure the Company’s port lease in San Juan, Puerto Rico were reclassified as ROU assets in connection with the adoption of ASC 842.

14.	Accrued liabilities

As of December 31, 2020 and 2019 accrued liabilities consisted of the following:

	December 31, 2020		December 31, 2019
Accrued development costs	$	16,631	$	25,037
Accrued interest		27,938		-
Accrued bonuses		17,344		14,991
Other accrued expenses		28,439		14,915
Total accrued liabilities	$	90,352	$	54,943

15.

Debt

As of December 31, 2020 and 2019, debt consisted of the following:

	December 31, 2020		December 31, 2019
Senior Secured Notes, due September 15, 2025	$	1,239,561	$	-
Term Loan Facility, due January 21, 2020		-		495,000
Senior Secured Bonds, due September 2034		-		70,960
Senior Secured Bonds, due December 2034		-		10,823
Senior Unsecured Bonds, due September 2036		-		42,274
Total debt	$	1,239,561	$	619,057

Senior Secured Notes

The Senior Secured Notes are guaranteed, jointly and severally, by certain of the Company’s subsidiaries, in addition to other collateral. The Senior Secured Notes may limit the Company’s ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The Senior Secured Notes also provide for customary events of default and prepayment provisions.

The Company 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 (as defined below), including related costs and expenses. The Company also used the remaining net proceeds, together with cash on hand, to redeem in full the outstanding Senior Secured Bonds and Senior Unsecured Bonds (as defined below), including related premiums, costs and expenses, terminating the Senior Secured Bonds and Senior Unsecured Bonds. The Company completed the redemption of the Senior Secured Bonds and Senior Unsecured Bonds on September 21, 2020.

In connection with the issuance of the Senior Secured Notes, the Company incurred $17,937 in origination, structuring and other fees. Issuance costs of $13,909 were deferred as a reduction of the principal balance of the Senior Secured Notes on the consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the Senior Secured Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the Senior Secured Notes and will be amortized over the remaining term of the Senior Secured Notes. As a portion of the repayment of the Credit Agreement was a modification, the Company recorded $4,028 of third-party fees in Selling, general and administrative in the consolidated statements of operations and comprehensive loss.

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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 set 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%. A portion of the proceeds received were utilized to extinguish the Term Loan Facility (defined below), including outstanding principal of $495,000.

The Credit Agreement was secured by mortgages on certain properties owned by the Company’s subsidiaries, in addition to other collateral. The Company was required to comply with certain financial covenants and other restricted covenants customary for credit agreements of this type, including restrictions on indebtedness, liens, acquisitions and investments, restricted payments and dispositions. The Credit Agreement also provided for customary events of default, prepayment and cure provisions.

On September 2, 2020, the Company repaid the full amount outstanding using proceeds from the Senior Secured Notes. Certain lenders in the Credit Agreement participated in the issuance of the Senior Secured Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the Senior Secured Notes.

Term Loan Facility

On August 16, 2018, the Company entered into a credit agreement with a syndicate of two lenders to borrow up to an aggregate principal amount of $240,000, and proceeds received from this credit agreement were utilized to repay prior debt facilities. On December 31, 2018, the Company amended this credit agreement to increase the available borrowing principal amount to $500,000 (as amended, the “Term Loan Facility”), and as of December 31, 2018, the Company had an outstanding principal balance of $280,000 under the Term Loan Facility. On March 21, 2019, the Company drew an additional $220,000, bringing the Company’s total outstanding borrowings to $500,000 under the Term Loan Facility.

All borrowings under the Term Loan Facility bore interest at a rate selected by the Company 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 the Company’s 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.

The Company incurred costs in connection with obtaining the Term Loan Facility, the extinguishment of the Company’s 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.

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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, the Company 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; no fees were due to lenders from the execution of this amendment. On January 15, 2020, the Company repaid the full amount outstanding including fees due to the lenders using proceeds from the Credit Agreement to extinguish the Term Loan Facility. In conjunction with the extinguishment of the Term Loan Facility, the Company recognized a Loss on extinguishment of debt of $9,557 in the consolidated statements of operations and comprehensive loss.

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 were secured by the dual-fired combined heat and power facility in Clarendon, Jamaica (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. Upon completion of construction of the CHP Plant in the fourth quarter of 2019, South Power issued an additional $63,000 in Senior Secured Bonds. The Company 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. After seven years, 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.

Interest Expense

Interest and related amortization of debt issuance costs recognized during major development and construction projects are capitalized and included in the cost of the project. Interest expense, net of amounts capitalized, recognized for the years ended December 31, 2020, 2019 and 2018 consisted of the following:

	Year Ended December 31,
	2020		2019		2018
Interest per contractual rates	$	76,176	$	32,283	$	9,363
Amortization of debt issuance costs		15,471		12,301		3,617
Total interest costs		91,647		44,584		12,980
Capitalized interest		25,924		25,172		1,732
Total interest expense	$	65,723	$	19,412	$	11,248

16.	Income taxes

In connection with the IPO, NFE LLC contributed the net proceeds from the IPO to NFI in exchange for NFI LLC Units, and NFE LLC became the managing member of NFI. NFI is a limited liability company that was treated as a partnership through December 31, 2020 for U.S. federal income tax purposes and for most applicable state and local income tax purposes. As a partnership, NFI was not subject to U.S. federal and certain state and local income taxes. Any taxable income or loss generated by NFI was passed through to and included in the taxable income or loss of its members, on a pro rata basis, subject to applicable tax regulations. NFE is subject to U.S. federal income taxes, in addition to state and local income taxes, with respect to its allocable share of any taxable income or loss of NFI. Additionally, NFI and its subsidiaries are subject to income taxes in the various foreign jurisdictions in which they operate.

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In connection with the IPO, NFE recorded a deferred tax asset of $42,783 related to the difference between its tax basis in its investment in NFI and NFE’s share of the financial statement carrying amount of the net assets of NFI. The deferred tax asset was recorded to equity and is fully offset by a valuation allowance also recorded to equity.

Subsequent to the Exchange Transactions completed on June 10, 2020, 100% of NFI’s operations are included in the NFE income tax provision; there was no impact on income tax expense due to the Exchange Transactions. Additionally, in the third quarter of 2020, the Company completed the Conversion; NFE LLC has been a corporation for U.S. federal tax purposes, and converting NFE LLC from a limited liability company to a corporation has no effect on the U.S. federal tax treatment of the Company or its shareholders.

The components of the Company’s loss before income taxes for the years ended December 31, 2020, 2019, and 2018 were as follows:

	Year Ended December 31,
	2020			2019			2018
United States	$	(166,571	)	$	(194,481	)	$	(74,873	)
Foreign		(92,577	)		(9,399	)		(3,647	)
Loss before taxes	$	(259,148	)	$	(203,880	)	$	(78,520	)

Income tax expense (benefit) is comprised of the following for the years ended December 31, 2020, 2019, and 2018:

	Year Ended December 31,
	2020		2019		2018
Current:
Domestic	$	-	$	-	$	-
Foreign		2,063		47		7
Total current tax expense		2,063		47		7
Deferred:
Domestic		-		-		-
Foreign		2,754		392		(345	)
Total deferred tax expense (benefit)		2,754		392		(345	)
Total provision for (benefit from) income taxes	$	4,817	$	439	$	(338	)

Effective Tax Rate

A reconciliation of the U.S. federal statutory income tax rate to the Company’s effective tax rate is as follows:

	Year Ended December 31,
	2020			2019			2018
Income tax at the statutory rate		21.0	%		21.0	%		-
Impact from foreign operations		(2.9	%)		-			-
Foreign tax rate differential		2.9	%		0.8	%		0.4	%
Foreign tax on foreign operations		0.4	%		2.9	%		-
Foreign permanent adjustments		(0.4	%)		5.0	%		-
Foreign valuation allowance		0.1	%		(10.8	%)		-
Domestic valuation allowance		(14.2	%)		(2.1	%)		-
Income attributable to non-controlling interest		(6.4	%)		(18.2	%)		-
Other		(2.4	%)		1.2	%		-
Effective income tax rate		(1.9	%)		(0.2	%)		0.4	%

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The primary items which decreased the Company’s effective income tax rate from the federal statutory rate in 2020 and 2019 were increases in domestic and foreign valuation allowances and income attributable to non-controlling interests. For 2018, the entire difference between the statutory and effective rate was attributable to foreign taxes.

During the years ended December 31, 2020, 2019 and 2018, the Company did not have any unrecognized tax benefits.

The following table summarizes the changes in the Company’s valuation allowance on deferred tax assets for the period indicated for the years ended December 31, 2020 and 2019:

	Year Ended December 31,
	2020		2019
Balance at the beginning of the period	$	80,911	$	241
Change in valuation allowance		51,586		80,670
Balance at the end of the period	$	132,497	$	80,911

The tax effect of each type of temporary difference and carryforward that give rise to a significant deferred tax asset or liability as of December 31, 2020 and 2019 are as follows:

	Year Ended December 31,
	2020			2019
Deferred tax assets:
Investment in NFI	$	64,553		$	46,185
Accrued interest		18,885			14,047
IRC Section 163(j) interest carryforward		6,909			182
Federal and state net operating loss carryforward		32,145			3,215
Foreign net operating loss carryforward		24,525			19,713
Share-based compensation		6,611			8,958
Lease liability		4,383			-
Other		1,252			224
Total deferred tax assets		159,263			92,524
Valuation allowance		(132,497	)		(80,911	)
Deferred tax assets, net of valuation allowance		26,766			11,613

Deferred tax liabilities:
Property and equipment		(22,566	)		(11,820	)
Lease asset		(4,215	)		-
Total deferred tax liabilities		(26,781	)		(11,820	)
Net deferred tax liabilities	$	(15	)	$	(207	)

U.S. Federal and State Jurisdictions

The Company and its subsidiaries file income tax returns in the U.S. federal and various state and local jurisdictions. The Company is not currently under income tax examination in any jurisdiction, and NFE filed its first corporate U.S. federal and state income tax returns for the period ended December 31, 2019. NFI was taxed as a U.S. partnership and controlled the underlying operations, thus the tax effects of temporary differences were captured through December 31, 2020 within the net deferred tax asset for the investment in the partnership.

As of December 31, 2020, NFE has approximately $147,928 of federal and $30,661 of state net operating loss carry forwards. The federal net operating losses are generally allowed to be carried forward indefinitely and can offset up to 80 percent of future taxable income. The state net operating losses relate to Florida and are generally allowed to be carried forward indefinitely.

Under the provisions of Internal Revenue Code Section 382, certain substantial changes in the Company’s ownership may result in a limitation on the amount of U.S. net operating loss carryforwards that can be utilized annually to offset future taxable income and taxes payable. A portion of the Company’s net operating loss carryforwards are subject to an annual limitation under Section 382 of the Internal Revenue Code.

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NFE recorded a valuation allowance against its U.S. federal and state deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized. As of December 31, 2020, the Company concluded, based on the weight of all available positive and negative evidence, those deferred tax assets are not more likely than not to be realized and accordingly, a valuation allowance has been recorded on this deferred tax asset as of December 31, 2020 for the amount not supported by reversing taxable temporary differences.

The Company has not recorded any deferred tax liabilities for undistributed earnings of controlled foreign corporations, primarily consisting of the Company’s Puerto Rican operations. The Company’s intent is to only make distributions from non-U.S. subsidiaries in the future when distributions can be made at no net tax cost; any remaining cash will be reinvested to grow operations in such subsidiaries. The Company has no material unremitted earnings from its non-U.S. subsidiaries.

On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act, which includes various income and payroll tax provisions, was signed into law by the U.S. government. In addition, various other coronavirus tax relief initiatives have been implemented around the world. This tax legislation did not have a material impact on the Company’s financial position, results of operations or cash flows for the year ended December 31, 2020.

Foreign Jurisdictions

NFI’s foreign subsidiaries file income tax returns in certain foreign jurisdictions. As of December 31, 2020, NFI’s foreign subsidiaries have approximately $86,176 of net operating loss carry forwards. Net operating losses of $64,819 incurred in Jamaica are generally allowed to be carried forward indefinitely. Net operating loss carryforwards of $11,830 incurred in Puerto Rico and Mexico will expire, if unused, between 2028 and 2029. Net operating loss carryforwards of $8,865 incurred in Ireland are generally allowed to be carried forward indefinitely.

The Company commenced operations in Puerto Rico during the year ended December 31, 2020 giving rise to cumulative profits, and the valuation allowance against a portion of the net deferred tax asset has been released. The Company recorded a valuation allowance against other foreign deferred tax assets to reduce the net carrying value to an amount that it believes is more likely than not to be realized.

The Company has subsidiaries incorporated in Bermuda. Under current Bermuda law, the Company is not required to pay taxes in Bermuda on either income or capital gains. The Company has received an undertaking from the Bermuda government that, in the event of income or capital gain taxes being imposed, it will be exempted from such taxes until 2035.

17.	Commitments and contingencies

In conjunction with its principal business activities, the Company enters into various firm commitments for the purchase, production, and transportation of LNG and natural gas, as well as engineering, procurement and construction agreements to develop the Company’s terminals and related infrastructure. The estimated future cash payments related to outstanding contractual commitments, at market prices as of December 31, 2020, is summarized as follows:

		2021				2022				2023				2024				_2024+
Purchase obligations		$	376,097			$	362,294			$	362,294			$	362,311			$	1,027,352

The future cash payments summarized above represent the Company’s minimum firm purchase commitments as of December 31, 2020.

In 2020, the Company entered into four LNG supply agreements for the purchase of 415 TBtu of LNG between 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 entered into in December 2018.

The Company has a contractual purchase commitment for feedgas with a remaining term of approximately five years. This commitment is designed to assure sources of supply and is not expected to be in excess of normal requirements. For agreements for supply where there is an active market, such agreements qualify for and the Company has elected the normal purchase exception under the derivatives guidance; therefore, the purchases under these contracts are included in Inventory and Cost of sales as incurred.

The Company’s lease obligations are discussed in Note 5. Leases.

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Contingencies

The Company may be subject to certain legal proceedings, claims and disputes that arise in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

18.	Earnings per share

	December 31, 2020			December 31, 2019
Numerator:
Net loss	$	(263,965	)	$	(204,319	)
Less: net loss attributable to non-controlling interests		81,818			170,510
Net loss attributable to Class A common stock	$	(182,147	)	$	(33,809	)
Denominator:
Weighted-average shares-basic and diluted		106,654,918			20,862,555

Net loss per share - basic and diluted	$	(1.71	)	$	(1.62	)

In connection with the closing of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares. The weighted average shares outstanding for the year ended December 31, 2020 are significantly lower than the Class A common stock outstanding on December 31, 2020 due to the timing of the Exchange Transactions.

The following table presents potentially dilutive securities excluded from the computation of diluted net loss per share for the periods presented because its effects would have been anti-dilutive.

	December 31, 2020		December 31, 2019
Unvested RSUs1		1,538,060		3,137,415
Class B shares2		-		144,342,572
Shannon Equity Agreement shares3		428,275		1,083,995
Total		1,966,335		148,563,982

1	Represents the number of instruments outstanding at the end of the period.

2	Class B shares at the end of the period are considered potentially dilutive Class A shares.

3	Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

19.	Share-based compensation

RSUs

The Company has granted RSUs to select officers, employees, non-employee members of the board of directors and select non-employees under the Incentive Plan. The fair value of RSUs on the grant date is estimated 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.

The following table summarizes the RSU activity for the year ended December 31, 2020:

	Restricted Share Units			Weighted-average grant date fair value per share
Non-vested RSUs as of December 31, 2019		3,137,415		$	13.44
Granted		109,409			14.47
Vested		(1,507,633	)		13.47
Forfeited		(201,131	)		13.51
Non-vested RSUs as of December 31, 2020		1,538,060		$	13.49

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The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the year ended December 31, 2020 and 2019:

	Year Ended December 31,
	2020		2019
Operations and maintenance	$	800	$	853
Selling, general and administrative		7,943		40,594
Total share-based compensation expense	$	8,743	$	41,447

For the years ended December 31, 2020 and 2019, cumulative compensation expense recognized for forfeited RSU awards of $914 and $2,248, respectively, was reversed. The Company recognizes the income tax benefits resulting from vesting of RSUs in the period of vesting, to the extent the compensation expense has been recognized.

As of December 31, 2020, the Company had 1,538,060 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $8,211. The non-vested RSUs will vest over a period from ten months to three years following the grant date. The weighted-average remaining vesting period of non-vested RSUs totaled 1.03 years as of December 31, 2020.

Performance Share Units (“PSUs”)

During the first quarter of 2020, the Company granted 1,109,777 PSUs to certain employees and non-employees. The PSUs contain a performance condition, and vesting will be determined based on achievement of a performance metric for the year ended December 31, 2021. The number of shares that will vest can range from zero to 2,219,554. For the year ended December 31, 2020, the Company determined that it was not probable that the performance condition required for any of the PSUs to vest would be achieved, and as such, no compensation expense has been recognized in the consolidated statements of operations and comprehensive loss. Unrecognized compensation costs if the maximum amount of shares were to vest based on the achievement of the performance condition was $30,864, and the weighted-average remaining vesting period of non-vested PSUs was one year as of December 31, 2020.

20.	Stockholder’s equity and Members’ equity

New Fortress Energy Holdings

In January 2018, the Company issued 665,843 common shares (no par value) to members of New Fortress Energy Holdings for $20,150 in proceeds.

New Fortress Energy LLC, New Fortress Energy Inc.

During the year ended December 31, 2019, the Company issued 2,716,252 shares of Class A shares in exchange for Class B shares, and 53,572 Class A shares were issued for vested RSUs.

As a result of the Exchange Transactions, 144,342,572 Class A shares were issued in exchange for all outstanding Class B shares. As a result of the Conversion, all outstanding Class A shares were converted to Class A common stock. In December 2020, NFE issued 5,882,352 shares of Class A common stock and received proceeds of $290,771, net of $1,221 in issuance costs.

The Company declared dividends of $0.10 per share in August and October 2020, totaling $33,742 in dividend payments during the year ended December 31, 2020.

21.	Related party transactions

Management services

The Company is majority owned by Messrs. Edens (our chief executive officer and chairman of our Board of Directors) and Nardone (one of our Directors) who are currently employed by Fortress Investment Group LLC (“Fortress”). In the ordinary course of business, Fortress, through affiliated entities, has historically charged the Company for administrative and general expenses incurred pursuant to its Management Services Agreement (“Management Agreement”). Upon completion of the IPO, the Management Agreement was terminated and replaced by an Administrative Services Agreement (“Administrative Agreement”) to charge the Company for similar administrative and general expenses. The charges under the Management Agreement and Administrative Agreement that are attributable to the Company totaled $7,291, $7,942 and $5,741 for the years ended December 31, 2020, 2019 and 2018, respectively. Costs associated with the Management Agreement and Administrative Agreement are included within Selling, general and administrative in the consolidated statements of operations and comprehensive loss. As of December 31, 2020 and 2019, $5,535 and $5,083 were due to Fortress, respectively.

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In addition to management and administrative services, an affiliate of Fortress owns and leases an aircraft chartered by the Company for business purposes in the course of operations. The Company incurred, at aircraft operator market rates, charter costs of $2,483 and $5,367 for the years ended December 31, 2020 and 2019, respectively. In 2018, such charges were incurred under the Management Agreement, and amounts incurred of $1,873 for the year ended December 31, 2018 are included in the activity and balances disclosed above. As of December 31, 2020 and 2019, $472 and $4,286 was due to this affiliate, respectively.

Land and office lease

The Company has leased land and office space from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. In April 2019, FECI sold the office building to a non-affiliate, and as such, the lease of the office space is no longer held with a related party. The Company recognized expense related to the land lease still held by a related party of $730, $396 and $260 during the years ended December 31, 2020, 2019 and 2018, respectively, which was included within Operations and maintenance in the consolidated statements of operations and comprehensive loss. The expense for the period that the building was owned by a related party during the year ended December 31, 2019 totaled $609, of which $386 was capitalized to Construction in progress and $223 was included in Selling, general and administrative in the consolidated statements of operations and comprehensive loss; no expense for the office space was incurred prior to 2019. As of December 31, 2020 and 2019, $316 and $0 was due to FECI, respectively. As of December 31, 2020, the Company has recorded a lease liability of $3,279 within Non-current lease liabilities on the consolidated balance sheet.

DevTech Investment

In August 2018, the Company entered into a consulting arrangement with DevTech Environment Limited (“DevTech”) to provide business development services to increase the customer base of the Company. DevTech also contributed cash consideration in exchange for a 10% interest in a consolidated subsidiary. The 10% interest is reflected as non-controlling interest in the Company’s consolidated financial statements. DevTech purchased 10% of a note payable due to an affiliate of the Company. As of December 31, 2020 and 2019, $715 and $815 was owed to DevTech on the note payable, respectively. The outstanding note payable due to DevTech is included in Other long-term liabilities on the consolidated balance sheets. The interest expense on the note payable due to DevTech was $77, $94 and $18 for the years ended December 31, 2020, 2019 and 2018 respectively. No interest has been paid, and accrued interest has been recognized within Accrued expenses on the consolidated balance sheets. As of December 31, 2020 and 2019, $343 and $443 was due from DevTech, respectively.

Fortress affiliated entities

Since 2017, the Company has provided certain administrative services to related parties including Fortress affiliated entities. As of December 31, 2020 and 2019, $1,334 and $1,134 were due from affiliates, respectively. There are no costs incurred by the Company as the Company is fully reimbursed for all costs incurred.

Additionally, an entity formerly affiliated with Fortress and currently owned by Messrs. Edens and Nardone provides certain administrative services to the Company, as well as providing office space under a month-to-month non-exclusive license agreement. The Company incurred rent and administrative expenses of approximately $2,357, $811 and $903 for the years ended December 31, 2020, 2019 and 2018, respectively. Additionally, the Company subleases a portion of office space to an affiliate of an entity managed by Fortress, and for the year ended December 31, 2020, $204 of rent and office related expenses were incurred by this affiliate. As of December 31, 2020 and 2019, $2,657 and $883 were due to Fortress affiliated entities, respectively.

Due to/from Affiliates

The table below summarizes the balances outstanding with affiliates as of December 31, 2020 and 2019:

	December 31, 2020		December 31, 2019
Amounts due to affiliates	$	8,980	$	10,252
Amounts due from affiliates		1,881		1,577

22.	Customer concentrations

For the year ended December 31, 2020, revenue from three significant customers constituted 88% of the total revenue and 83% of trade receivables. For the year ended December 31, 2019, revenue from two significant customers constituted 74% of the total revenue and 85% of trade receivables, and for the year ended December 31, 2018, one significant customer constituted 87% of total revenue. Prior to the adoption of ASC 842, the Company recognized a direct financing leases within the Company’s agreement with this customer. As of December 31, 2019, 99% of the Finance leases, net balance was attributed to this significant customer.

During the years ended December 31, 2020, 2019 and 2018, revenue from external customers that were derived from customers located in the United States were $135,702, $21,386 and $7,214, respectively, and from customers outside of the United States were $315,948, $167,739 and $105,087, respectively, primarily derived from customers in the Caribbean. The Company attributes revenue from external customers to the country in which the party to the applicable agreement has its principal place of business.

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As of December 31, 2020 and 2019, long lived assets, which are all non-current assets excluding investment in equity securities, restricted cash, deferred tax assets and intangible assets, located in the United States were $442,199 and $360,860 respectively, and long lived assets located outside of the United States were $639,370 and $470,749, respectively, primarily located in the Caribbean.

23.	Unaudited quarterly financial data

Summarized quarterly financial data for the years ended December 31, 2020 and 2019 are as follows:

(in thousands of U.S. dollars, except per share data)
	Three Months Ended
	March 31, 2020 (1)			June 30, 2020 (1, 2)			September 30, 2020			December 31, 2020

Revenues	$	74,530		$	94,566		$	136,858		$	145,696
Operating loss		(36,169	)		(148,273	)		11,053			18,031
Net loss		(60,223	)		(166,587	)		(36,670	)		(485	)
Net (loss) income attributable to stockholders		(8,466	)		(137,493	)		(36,358	)		170
Basic and diluted (loss) income per share (3)		(0.32	)		(2.40	)		(0.21	)		0.00

	Three Months Ended
	March 31, 2019			June 30, 2019			September 30, 2019			December 31, 2019

Revenues	$	29,951		$	39,766		$	49,656		$	69,752
Operating loss		(59,337	)		(43,959	)		(47,726	)		(36,253	)
Net loss		(60,292	)		(51,233	)		(54,424	)		(38,370	)
Net loss attributable to stockholders		(13,557	)		(6,186	)		(6,723	)		(7,343	)
Basic and diluted loss per share (3)		(0.96	)		(0.28	)		(0.30	)		(0.30	)

(1)

Operating loss, net loss and net loss attributable to stockholders for the three months ended March 31, 2020 and June 30, 2020 reflect the adoption of ASC 326. The Company adopted ASC 326 in the third quarter of 2020 with an effective date of January 1, 2020, due to the loss of EGC status in that quarter.

(2)

Operating loss, net loss and net loss attributable to stockholders for the three months ended June 30, 2020 includes a termination charge of $105,000 associated with an agreement with one of the Company’s LNG suppliers to terminate the obligation to purchase any LNG from this supplier for the remainder of 2020.

(3)	Basic and diluted earnings per share are computed independently for each of the quarters presented. Therefore, the sum of quarterly basic and diluted per share information may not equal annual basic and diluted earnings per share.

24.	Subsequent events

Hygo Merger Agreement

On January 13, 2021, NFE, Hygo Energy Transition Ltd., a Bermuda exempted company (“Hygo”), Golar LNG Limited, a Bermuda exempted company (“GLNG”), Stonepeak Infrastructure Fund II Cayman (G) Ltd. (“Stonepeak”), and Lobos Acquisition Ltd., a Bermuda exempted company and an indirect, wholly-owned subsidiary of NFE (“Hygo Merger Sub”), entered into an Agreement and Plan of Merger (the “Hygo Merger Agreement”), pursuant to which Hygo Merger Sub will merge with and into Hygo (the “Hygo Merger”), with Hygo surviving the Hygo Merger as a wholly owned subsidiary of NFE. As of the date of the Hygo Merger Agreement, each of GLNG and Stonepeak owned 50% of the outstanding common shares, par value $1.00 per share, of Hygo, and Stonepeak owned all of Hygo’s outstanding redeemable preferred shares, par value $5.00 per share. At the effective time of the Hygo Merger: (i) GLNG will receive 18.6 million shares of NFE Class A common stock and an aggregate of $50 million in cash and (ii) Stonepeak will receive 12.7 million shares of NFE Class A common stock and an aggregate of $530 million in cash. The Hygo Merger Agreement may be terminated by NFE or Hygo under certain circumstances, including, among others, by either NFE or Hygo if the closing of the Hygo Merger has not occurred on or before July 12, 2021.

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GMLP Merger Agreement

On January 13, 2021, NFE entered into an Agreement and Plan of Merger (the “GMLP Merger Agreement”) with Golar LNG Partners LP, a Marshall Islands limited partnership (“GMLP”), Golar GP LLC, a Marshall Islands limited liability company and the general partner of GMLP (the “General Partner”), Lobos Acquisition LLC, a Marshall Islands limited liability company and an indirect subsidiary of NFE (“GMLP Merger Sub”), and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales and an indirect subsidiary of NFE (“GP Buyer”), pursuant to which GMLP Merger Sub will merge with and into GMLP, with GMLP surviving the merger as an indirect subsidiary of NFE (the “GMLP Merger”).

Suape Development

On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal at the Port of Suape, Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecem Energia S.A. (“Pecem”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold certain 15-year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil. We will seek to obtain the necessary approvals to transfer the power purchase agreements to the Port of Suape and plan to construct a gas-fired power plant and LNG import terminal at the Port of Suape. The Company paid approximately $9 million at closing in total and will make additional payments to the sellers based on certain contingent considerations.

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Schedule II

Description	Balance at Beginning of Year		Additions⁽¹⁾		Deductions			Balance at End of Year

Year ended December 31, 2020

Allowance for doubtful accounts	$	-	$	-	$	-		$	-
Allowance for expected credit losses		-		316		-			316
Total allowance		-		316		-			316

Year ended December 31, 2019

Allowance for doubtful accounts		257		-		(257	)		-

Year ended December 31, 2018

Allowance for doubtful accounts		-		257		-			257

Note

⁽¹⁾	Amount expensed in included within Selling, general and administrative.

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