10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2021

OR

☐ 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

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

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

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

As of May 3, 2021, the registrant had 206,698,564 Class A common stock outstanding.

TABLE OF CONTENTS

GLOSSARY OF TERMS		ii
CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS		iii
PART I FINANCIAL INFORMATION		4
Item 1.	Financial Statements.	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	26
Item 3.	Quantitative and Qualitative Disclosures About Market Risks.	40
Item 4.	Controls and Procedures.	41
PART II OTHER INFORMATION		42
Item 1.	Legal Proceedings.	42
Item 1A.	Risk Factors.	42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	90
Item 3.	Defaults upon Senior Securities.	90
Item 4.	Mine Safety Disclosures.	90
Item 5.	Other Information.	90
Item 6.	Exhibits.	91
SIGNATURES		94

i

GLOSSARY OF TERMS

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

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
FERC	Federal Energy Regulatory Commission
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 gallons of LNG
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 gallons of LNG

ii

CAUTIONARY STATEMENT ON FORWARD-LOOKING STATEMENTS

This Quarterly Report contains forward-looking statements regarding, among other things, our plans, strategies, prospects and projections, both business and financial. All statements contained in this Quarterly 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 (as defined herein) 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;

• We may be unable to successfully integrate the businesses and realize the anticipated benefits of the 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 Quarterly Report.

All forward-looking statements speak only as of the date of this Quarterly 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 our Annual Report on Form 10-K for the year ended December 31, 2020 (our “Annual Report”), this Quarterly Report and in our other filings with the Securities and Exchange Commission (the “SEC”). 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.

iii

PART I

FINANCIAL INFORMATION

Item 1. Financial Statements.

New Fortress Energy Inc.

Condensed Consolidated Balance Sheets

As of March 31, 2021 and December 31, 2020

(Unaudited, in thousands of U.S. dollars, except share amounts)

	March 31, 2021			December 31, 2020
Assets
Current assets
Cash and cash equivalents	$	360,130		$	601,522
Restricted cash		4,072			12,814
Receivables, net of allowances of $203 and $98, respectively		95,729			76,544
Inventory		28,031			22,860
Prepaid expenses and other current assets, net		60,245			48,270
Total current assets		548,207			762,010
Restricted cash		15,000			15,000
Construction in progress		337,691			234,037
Property, plant and equipment, net		607,003			614,206
Right-of-use assets		131,575			141,347
Intangible assets, net		65,934			46,102
Finance leases, net		7,501			7,044
Deferred tax assets, net		5,060			2,315
Other non-current assets, net		114,140			86,030
Total assets	$	1,832,111		$	1,908,091
Liabilities
Current liabilities
Accounts payable	$	27,970		$	21,331
Accrued liabilities		88,809			90,352
Current lease liabilities		34,857			35,481
Due to affiliates		10,859			8,980
Other current liabilities		33,375			35,006
Total current liabilities		195,870			191,150
Long-term debt		1,239,799			1,239,561
Non-current lease liabilities		74,363			84,323
Deferred tax liabilities, net		5,194			2,330
Other long-term liabilities		25,704			15,641
Total liabilities		1,540,930			1,533,005
Commitments and contingences (Note 17)
Stockholders’ equity
Class A common stock, $0.01 par value, 750.0 million shares authorized, 175.3 million issued and outstanding as of March 31, 2021; 174.6  million issued and outstanding as of December 31, 2020		1,746			1,746
Additional paid-in capital		551,135			594,534
Accumulated deficit		(267,406	)		(229,503	)
Accumulated other comprehensive income		59			182
Total stockholders' equity attributable to NFE		285,534			366,959
Non-controlling interest		5,647			8,127
Total stockholders' equity		291,181			375,086
Total liabilities and stockholders' equity	$	1,832,111		$	1,908,091

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

New Fortress Energy Inc.

Condensed Consolidated Statements of Operations and Comprehensive Loss

For the three months ended March 31, 2021 and 2020

(Unaudited, in thousands of U.S. dollars, except share and per share amounts)

	Three Months Ended March 31,
	2021			2020
Revenues
Operating revenue	$	91,196		$	63,502
Other revenue		54,488			11,028
Total revenues		145,684			74,530
Operating expenses
Cost of sales		96,671			68,216
Operations and maintenance		16,252			8,483
Selling, general and administrative		45,181			28,538
Contract termination charges and loss on mitigation sales		-			208
Depreciation and amortization		9,890			5,254
Total operating expenses		167,994			110,699
Operating loss		(22,310	)		(36,169	)
Interest expense		18,680			13,890
Other (income) expense, net		(604	)		611
Loss on extinguishment of debt, net		-			9,557
Loss before taxes		(40,386	)		(60,227	)
Tax benefit		(877	)		(4	)
Net loss		(39,509	)		(60,223	)
Net loss attributable to non-controlling interest		1,606			51,757
Net loss attributable to stockholders	$	(37,903	)	$	(8,466	)
Net loss per share – basic and diluted	$	(0.21	)	$	(0.32	)
Weighted average number of shares outstanding – basic and diluted		176,500,576			26,029,492
Other comprehensive loss:
Net loss	$	(39,509	)	$	(60,223	)
Currency translation adjustment		997			369
Comprehensive loss		(40,506	)		(60,592	)
Comprehensive loss attributable to non-controlling interest		2,480			52,073
Comprehensive loss attributable to stockholders	$	(38,026	)	$	(8,519	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

5

New Fortress Energy Inc.

Condensed Consolidated Statements of Changes in Stockholders’ Equity

For the three months ended March 31, 2021 and 2020

(Unaudited, in thousands of U.S. dollars, except share amounts)

														Additional						Accumulated other			Non-			Total
	Class A shares				Class B shares				Class A common stock					paid-in			Accumulated			comprehensive			controlling			stockholders'
	Shares		Amount		Shares		Amount		Shares			Amount		capital			deficit			(loss) income			interest			equity
Balance as of December 31, 2020		-	$	-		-	$	-		174,622,862		$	1,746	$	594,534		$	(229,503	)	$	182		$	8,127		$	375,086
Net loss		-		-		-		-		-			-		-			(37,903	)		-			(1,606	)		(39,509	)
Other comprehensive loss		-		-		-		-		-			-		-			-			(123	)		(874	)		(997	)
Share-based compensation expense		-		-		-		-		-			-		1,770			-			-			-			1,770
Issuance of shares for vested RSUs		-		-		-		-		1,335,787			-		-			-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		-		-		-		-		(638,235	)		-		(27,571	)		-			-			-			(27,571	)
Dividends		-		-		-		-		-			-		(17,598	)		-			-			-			(17,598	)
Balance as of March 31, 2021		-	$	-		-	$	-		175,320,414		$	1,746	$	551,135		$	(267,406	)	$	59		$	5,647		$	291,181

															Additional					Accumulated other			Non-			Total
	Class A shares						Class B shares				Class A common stock				paid-in		Accumulated			comprehensive			controlling			stockholders'
	Shares			Amount			Shares		Amount		Shares		Amount		capital		deficit			(loss) income			interest			equity
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	)
Net loss		-			-			-		-		-		-		-		(8,466	)		-			(51,757	)		(60,223	)
Other comprehensive loss		-			-			-		-		-		-		-		-			(53	)		(316	)		(369	)
Share-based compensation expense		-			2,508			-		-		-		-		-		-			-			-			2,508
Issuance of shares for vested RSUs		1,212,907			-			-		-		-		-		-		-			-			-			-
Shares withheld from employees related to share-based compensation, at cost		(583,508	)		(6,132	)		-		-		-		-		-		-			-			-			(6,132	)
Balance as of March 31, 2020		24,236,495		$	127,034			144,342,572	$	-		-	$	-	$	-	$	(55,822	)	$	(83	)	$	242,666		$	313,795

The accompanying notes are an integral part of these condensed consolidated financial statements.

6

New Fortress Energy Inc.

Condensed Consolidated Statements of Cash Flows

For the three months ended March 31, 2021 and 2020

(Unaudited, in thousands of U.S. dollars)

	Three Months Ended March 31,
	2021			2020
Cash flows from operating activities
Net loss	$	(39,509	)	$	(60,223	)
Adjustments for:
Amortization of deferred financing costs		400			3,353
Depreciation and amortization		10,160			5,481
Loss on extinguishment and financing expenses		-			9,557
Deferred taxes		(1,412	)		(18	)
Share-based compensation		1,770			2,508
Other		393			2,656
Changes in operating assets and liabilities:
(Increase) Decrease in receivables		(19,223	)		5,752
(Increase) Decrease in inventories		(5,171	)		34,830
(Increase) in other assets		(36,943	)		(54,080	)
Decrease in right-of-use assets		9,772			9,263
(Decrease) Increase in accounts payable/accrued liabilities		(22,399	)		2,132
Increase (Decrease) in amounts due to affiliates		1,879			(2,875	)
(Decrease) in lease liabilities		(10,584	)		(9,170	)
(Decrease) in other liabilities		(1,119	)		(477	)
Net cash used in operating activities		(111,986	)		(51,311	)
Cash flows from investing activities
Capital expenditures		(80,810	)		(56,098	)
Entities acquired in asset acquisitions, net of cash acquired		(8,817	)		-
Other investing activities		(630	)		50
Net cash used in investing activities		(90,257	)		(56,048	)
Cash flows from financing activities
Proceeds from borrowings of debt		-			832,144
Payment of deferred financing costs		(670	)		(14,069	)
Repayment of debt		-			(506,402	)
Payments related to tax withholdings for share-based compensation		(29,564	)		(6,084	)
Payment of dividends		(17,657	)		-
Net cash (used in) provided by financing activities		(47,891	)		305,589
Net (decrease) increase in cash, cash equivalents and restricted cash		(250,134	)		198,230
Cash, cash equivalents and restricted cash – beginning of period		629,336			93,035
Cash, cash equivalents and restricted cash – end of period	$	379,202		$	291,265
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	$	26,311		$	13,359
Liabilities associated with consideration paid for entities acquired in asset acquisitions		11,845			-

The accompanying notes are an integral part of these condensed consolidated financial statements.

7

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 principal accounting policies adopted are set out below.

(a) Basis of presentation and principles of consolidation

The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with GAAP and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. The condensed 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. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020.

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 condensed consolidated balance sheets and statements of operations and comprehensive loss of New Fortress Energy Holdings for all periods prior to the IPO.

8

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.

Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s condensed 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 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 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 condensed 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 March 31, 2021, NFE had 175,320,414 Class A common stock outstanding.

(b) Revenue recognition

The Company’s contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from 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.

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 condensed 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 condensed 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 condensed 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 condensed consolidated statements of operations and comprehensive loss.

9

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 condensed consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed 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 condensed 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 condensed 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.

3. Adoption of new and revised standards

(a) New standards, amendments and interpretations issued but not effective for the financial year beginning January 1, 2021:

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 December 2019, 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 adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

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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 March 31, 2021 and December 31, 2020, receivables related to revenue from contracts with customers totaled $95,753 and $76,431, respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $203 and $98, 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.

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 condensed 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 March 31, 2021 and December 31, 2020 are detailed below:

	March 31, 2021		December 31, 2020
Contract assets, net-current	$	5,268	$	3,673
Contract assets, net-non-current		30,685		23,972
Total contract assets, net	$	35,953	$	27,645
Contract liabilities	$	10,704	$	8,399
Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year	$	942	$	6,542

Contract assets are presented net of expected credit losses of $484 and $372 as of March 31, 2021 and December 31, 2020, respectively. As of March 31, 2021, the Company has unbilled receivables, net of current expected credit losses, of $6,729, of which $356 is presented within Other current assets and $6,373 is presented within Other non-current assets on the condensed consolidated balance sheet. 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 $91,196 and $63,502 for the three months ended March 31, 2021 and 2020, respectively.

Other revenue includes revenue for development services as well as lease and other revenue. The table below summarizes the balances in Other revenue:

	Three Months Ended March 31,
	2021		2020
Development services revenue	$	54,071	$	10,071
Lease and other revenue		417		957
Total other revenue	$	54,488	$	11,028

Development services revenue recognized in the three months ended March 31, 2021 included $45,618 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 $10,478,395 as of March 31, 2021, 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
Remainder of 2021	$	278,546
2022		504,522
2023		504,708
2024		499,842
2025		494,081
Thereafter		8,196,696
Total	$	10,478,395

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 March 31, 2021, the Company has capitalized $11,434 of which $604 of these costs is presented within Other current assets and $10,830 is presented within Other non-current assets on the condensed consolidated balance sheets. As of December 31, 2020, the Company had capitalized $11,276, of which $588 of these costs was presented within Other current assets and $10,688 was presented within Other non-current assets on the condensed 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.

5. Leases

Lessee

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.

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For the three months ended March 31, 2021 and 2020, the Company’s operating lease cost recorded within the condensed consolidated statements of operations and comprehensive loss were as follows:

	Three Months Ended March 31,
	2021		2020
Fixed lease cost	$	11,745	$	10,267
Variable lease cost		693		639
Short-term lease cost		722		286
Lease cost - Cost of sales	$	11,036	$	9,351
Lease cost - Operations and maintenance		557		388
Lease cost - Selling, general and administrative		1,567		1,453

For the three months ended March 31, 2021, the Company has capitalized $1,199 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 condensed consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the three months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021		2020
Operating cash outflows for operating lease liabilities	$	12,660	$	10,096
Right-of-use assets obtained in exchange for new operating lease liabilities		-		127,994

The future payments due under operating leases as of March 31, 2021 are as follows:

	Operating Leases
Due remainder of 2021	$	30,754
2022		29,931
2023		18,719
2024		17,866
2025		10,680
Thereafter		50,019
Total lease payments		157,969
Less: effects of discounting		48,749
Present value of lease liabilities	$	109,220
Current lease liability	$	34,857
Non-current lease liability		74,363

As of March 31, 2021, the weighted-average remaining lease term for all operating leases was 7.3 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 March 31, 2021 was 8.4%.

The Company has entered into several leases for ISO tanks and an office space that have not commenced as of March 31, 2021 with noncancelable terms of 5 years and including fixed payments of approximately $24 million.

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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:

	March 31, 2021			December 31, 2020
Property, plant and equipment	$	18,747		$	18,394
Accumulated depreciation		(1,189	)		(932	)
Property, plant and equipment, net	$	17,558		$	17,462

The following table shows the expected future lease payments as of March 31, 2021, for the remainder of 2021 through 2025 and thereafter:

	Future cash receipts
	Financing leases		Operating leases
Remainder of 2021	$	1,671	$	220
2022		2,149		286
2023		2,134		288
2024		2,135		273
2025		2,001		234
Thereafter		5,705		743
Total	$	15,795	$	2,044
Less: Imputed interest		6,718
Present value of total lease receipts	$	9,077
Current finance leases, net	$	1,576
Non-current finance leases, net		7,501

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).

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The following table presents the Company’s financial assets and financial liabilities that are measured at fair value as of March 31, 2021 and December 31, 2020:

	March 31, 2021
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets
Cash and cash equivalents	$	360,130	$	-	$	-	$	360,130	Market approach
Restricted cash		19,072		-		-		19,072	Market approach
Investment in equity securities		294		-		1,849		2,143	Market approach
Total	$	379,496	$	-	$	1,849	$	381,345
Liabilities
Derivative liability¹	$	-	$	-	$	20,692	$	20,692	Income approach
Equity agreement²		-		-		21,223		21,223	Income approach
Total	$	-	$	-	$	41,915	$	41,915

	December 31, 2020
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets
Cash and cash equivalents	$	601,522	$	-	$	-	$	601,522	Market approach
Restricted cash		27,814		-		-		27,814	Market approach
Investment in equity securities		256		-		1,000		1,256	Market approach
Total	$	629,592	$	-	$	1,000	$	630,592
Liabilities
Derivative liability¹	$	-	$	-	$	10,716	$	10,716	Income approach
Equity agreement²		-		-		22,768		22,768	Income approach
Total	$	-	$	-	$	33,484	$	33,484

⁽¹⁾ Consideration due to the sellers in assets acquistions when certain contingent events occur.

⁽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 to the derivative liability and equity agreement, recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss, and currency translation adjustment, recorded within the Other comprehensive loss, for the three months ended March 31, 2021 and 2020:

	March 31, 2021			March 31, 2020
Fair value adjustment - (Gain)	$	(425	)	$	(1,617	)
Currency translation adjustment - (Gain)		(1,664	)		(537	)

Activity during the three months ended March 31, 2021 included the recognition of additional derivative liabilities from transactions accounted for as asset acquisitions of $10,520 (Note 21. Asset acquisitions). During the three months ended March 31, 2021 and 2020, the Company had no settlements of the equity agreement or derivative liabilities or any transfers in or out of Level 3 in the fair value hierarchy.

The liability associated with the equity agreement of $21,223 and $22,768 as of March 31, 2021 and December 31, 2020, respectively, is recorded within Other current liabilities on the condensed consolidated balance sheets. The liability associated with the derivative liabilities of $20,692 and $10,716 as of March 31, 2021 and December 31, 2020, respectively, is recorded within Other long-term liabilities on the condensed consolidated balance sheets.

The Company estimates fair value of outstanding debt using quoted market prices. The fair value of the 2025 Notes (defined below in Note 15. Debt) was approximately $1,285,588 as of March 31, 2021. The fair value estimate is classified as Level 2 in the fair value hierarchy.

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7. Restricted cash

As of March 31, 2021 and December 31, 2020, restricted cash consisted of the following:

	March 31, 2021		December 31, 2020
Collateral for performance under customer agreements	$	15,000	$	15,000
Collateral for LNG purchases		2,916		11,664
Collateral for letters of credit and performance bonds		906		900
Other restricted cash		250		250
Total restricted cash	$	19,072	$	27,814
Current restricted cash	$	4,072	$	12,814
Non-current restricted cash		15,000		15,000

8. Inventory

As of March 31, 2021 and December 31, 2020, inventory consisted of the following:

	March 31, 2021		December 31, 2020
LNG and natural gas inventory	$	18,213	$	13,986
Automotive diesel oil inventory		4,463		3,986
Bunker fuel, materials, supplies and other		5,355		4,888
Total inventory	$	28,031	$	22,860

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 condensed consolidated statements of operations and comprehensive loss. No adjustments were recorded during the three months ended March 31, 2021 and 2020.

9. Prepaid expenses and other current assets

As of March 31, 2021 and December 31, 2020, prepaid expenses and other current assets consisted of the following:

	March 31, 2021		December 31, 2020
Prepaid LNG	$	20,605	$	11,987
Prepaid expenses		6,806		4,941
Due from affiliates (Note 20)		1,912		1,881
Other current assets		30,922		29,461
Total prepaid expenses and other current assets, net	$	60,245	$	48,270

Other current assets as of March 31, 2021 and December 31, 2020 primarily consists of receivables for recoverable taxes.

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10. Construction in progress

The Company’s construction in progress activity during the three months ended March 31, 2021 is detailed below:

	March 31, 2021
Balance at beginning of period	$	234,037
Additions		105,761
Transferred to property, plant and equipment, net or finance leases		(2,107	)
Balance at end of period	$	337,691

Interest expense of $2,641 and $9,606, inclusive of amortized debt issuance costs, was capitalized for the three months ended March 31, 2021 and 2020, respectively.

11. Property, plant and equipment, net

As of March 31, 2021 and December 31, 2020, the Company’s property, plant and equipment, net consisted of the following:

	March 31, 2021			December 31, 2020
Terminal and power plant equipment	$	189,197		$	188,855
CHP facilities		119,723			119,723
Gas terminals		120,810			120,810
ISO containers and other equipment		102,010			100,137
LNG liquefaction facilities		63,213			63,213
Gas pipelines		58,974			58,974
Land		16,582			16,246
Leasehold improvements		8,723			8,723
Accumulated depreciation		(72,229	)		(62,475	)
Total property, plant and equipment, net	$	607,003		$	614,206

Depreciation for the three months ended March 31, 2021 and 2020 totaled $9,842 and $5,211, respectively, of which $270 and $227, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive loss.

12. Intangible assets

The following table summarizes the composition of intangible assets as of March 31, 2021 and December 31, 2020:

	March 31, 2021
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Permits	$	49,467	$	2,607	$	46,860		38
Acquired power purchase agreements		16,499		-		16,499		17
Easements		1,559		203		1,356		30
Indefinite-lived intangible assets
Easements		1,219		-		1,219		n/a
Total intangible assets	$	68,744	$	2,810	$	65,934

	December 31, 2020
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
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

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During the first quarter of 2021, the Company recognized additions to permits of $5,776 acquired in a transaction accounted for as asset acquisition related to licenses and rights to develop a gas-fired power plant and associated infrastructure in the Port of Suape in Brazil. The Company also acquired rights operated a power generation facility and sell power in Brazil of $16,585 (see Note 21. Asset acquisitions).

As of March 31, 2021 and December 31, 2020, the weighted-average remaining amortization periods for the intangible assets were 31.0 and 37.5 years, respectively. Amortization expense for the three months ended March 31, 2021 and 2020 totaled $295 and $270, respectively.

13. Other non-current assets

As of March 31, 2021 and December 31, 2020, Other non-current assets consisted of the following:

	March 31, 2021		December 31, 2020
Nonrefundable deposit	$	30,728	$	28,509
Contract asset, net (Note 4)		30,685		23,972
Cost to fulfill (Note 4)		10,830		10,688
Unbilled receivables, net (Note 4)		6,373		6,462
Upfront payments to customers		10,501		6,330
Other		25,023		10,069
Total other non-current assets, net	$	114,140	$	86,030

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 issuance costs associated with the 2026 Notes and Revolving Facility (both defined below) that closed in April 2021, 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”).  During the first quarter of 2021, the investee completed a qualified financing which converted the Company’s investment into preferred shares; the Company also invested an additional $750 in this qualified financing.

14. Accrued liabilities

As of March 31, 2021 and December 31, 2020, accrued liabilities consisted of the following:

	March 31, 2021		December 31, 2020
Accrued development costs	$	25,222	$	16,631
Accrued interest		3,516		27,938
Accrued bonuses		6,171		17,344
Other accrued expenses		53,900		28,439
Total accrued liabilities	$	88,809	$	90,352

Other accrued expenses includes accrued legal, accounting and other transaction costs associated with the Mergers and the issuance of the 2026 Notes and the Revolving Facility (all defined below).

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15. Debt

As of March 31, 2021 and December 31, 2020, debt consisted of the following:

	March 31, 2021		December 31, 2020
Senior Secured Notes, due September 15, 2025	$	1,239,799	$	1,239,561
Total debt	$	1,239,799	$	1,239,561

2025 Notes

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

The 2025 Notes are guaranteed, jointly and severally, by certain of the Company’s subsidiaries, in addition to other collateral. The 2025 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 2025 Notes also provide for customary events of default and prepayment provisions.

The Company used a portion of the net cash proceeds received from the 2025 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 2025 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 2025 Notes on the condensed consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the 2025 Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes. As a portion of the repayment of the Credit Agreement was a modification, in the third quarter of 2020, the Company recorded $4,028 of third-party fees in Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss.

On December 17, 2020, the Company issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,436. As of March 31, 2021, total remaining unamortized deferred financing costs for all outstanding debt were $10,201.

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.

In connection with obtaining the Credit Agreement and the extinguishment of the Term Loan Facility, the Company incurred $37,051 in origination, structuring and other fees which were recognized as a reduction of the principal balance of the Credit Agreement on the condensed consolidated balance sheets.

On September 2, 2020, the Company repaid the full amount outstanding using proceeds from the 2025 Notes. Certain lenders in the Credit Agreement participated in the issuance of 2025 Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the condensed consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the 2025 Notes.

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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 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 condensed 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 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.

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 condensed consolidated balance sheets. On September 21, 2020, the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the 2025 Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds in the third quarter of 2020, the Company recognized a loss on extinguishment of debt of $7,195, including the write-off of $3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $3,601.

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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 three months ended March 31, 2021 and 2020 consisted of the following:

	Three Months Ended March 31,
	2021		2020
Interest per contractual rates	$	20,834	$	18,874
Amortization of debt issuance costs		487		4,622
Total interest costs		21,321		23,496
Capitalized interest		2,641		9,606
Total interest expense	$	18,680	$	13,890

16. Income taxes

In the third quarter of 2020, the Company completed the Conversion; 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.

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. Prior to the Exchange Transactions, NFI was a limited liability company that was treated as a partnership 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. 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. 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.

In the first quarter of 2021, the Company contributed all NFI LLC units into a wholly owned corporate entity, which had the effect of terminating NFI LLC’s treatment as a partnership for U.S. federal income tax purposes. The transaction does not have a material impact on income tax expense.

The effective tax rate for the three months ended March 31, 2021 was 2.2%, compared to 0.01% for the three months ended March 31, 2020. The total tax benefit for the three months ended March 31, 2021 was $877, compared to $4 for the three months ended March 31, 2020, and the increase in benefit for the three months ended March 31, 2021 was primarily driven by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $3,010 partially offset by income tax expense recorded for certain profitable non-U.S. operations.

The primary items which decreased the Company’s effective tax rate for the three months ended March 31, 2021 and March 31, 2020 from the U.S. federal statutory rate of 21% were valuation allowances recorded against a portion of the Company’s current period losses and earnings generated in non-U.S. jurisdictions with lower tax rates.

The Company has not recorded a liability for uncertain tax positions as of March 31, 2021. The Company remains subject to periodic audits and reviews by the taxing authorities, and NFE’s returns since its formation remain open for examination.

17. Commitments and 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.

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18. Earnings per share

	Three Months Ended March 31,
	2021			2020
Numerator:
Net loss	$	(39,509	)	$	(60,223	)
Less: net loss attributable to non-controlling interests		1,606			51,757
Net loss attributable to Class A common stock	$	(37,903	)	$	(8,466	)
Denominator:
Weighted-average shares-basic and diluted		176,500,576			26,029,492
Net loss per share - basic and diluted	$	(0.21	)	$	(0.32	)

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.

	Three Months Ended March 31,
	2021		2020
Unvested RSUs1		869,262		1,890,125
Class B shares2		-		144,342,572
Shannon Equity Agreement shares3		464,267		1,635,462
Total		1,333,529		147,868,159

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. In connection with the closing of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares.

³ Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

The Company declared dividends of $17,598 ($0.10 per share); during the first quarter of 2021, the Company paid $17,657 of dividends, inclusive of dividends that were accrued in prior periods.

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 New Fortress Energy Inc. 2019 Omnibus 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 three months ended March 31, 2021:

	Restricted Share Units			Weighted-average grant date fair value per share
Non-vested RSUs as of December 31, 2020		1,538,060		$	13.49
Granted		-			-
Vested		(665,781	)		13.54
Forfeited		(3,017	)		13.51
Non-vested RSUs as of March 31, 2021		869,262		$	13.45

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The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the three  months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021		2020
Operations and maintenance	$	222	$	237
Selling, general and administrative		1,548		2,271
Total share-based compensation expense	$	1,770	$	2,508

For the three months ended March 31, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $0 and $61, 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 March 31, 2021, the Company had 869,262 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $6,400. 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 1.05 years as of March 31, 2021.

Performance Share Units (“PSUs”)

During the first quarter of 2020 and 2021, the Company granted PSUs to certain employees and non-employees that contain a performance condition. Vesting will be determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. For the three months ended March 31, 2021, 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 condensed consolidated statements of operations and comprehensive loss

PSUs Granted	Units Granted	Range of Vesting	Unrecognized Compensation Cost(1)		Weighted Average Remaining Vesting Period
Q1 2020	1,109,777	0 to 2,219,554	$	30,864	0.75 years
Q1 2021	400,507	0 to 801,014	$	32,577	1.75 years

(1) Unrecognized compensation cost is based upon the maximum amount of shares that could vest

20. 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 Administrative Agreement that are attributable to the Company totaled $1,927 and $2,231 for the three months ended March 31, 2021 and 2020, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss. As of March 31, 2021 and December 31, 2020, $7,145 and $5,535 were due to Fortress, respectively.

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 $1,609 and $1,239 for the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, $554 and $472 was due to this affiliate, respectively.

Land lease

The Company has leased land from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $126 and $103 during the three months ended March 31, 2021 and 2020, respectively, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive loss. As of March 31, 2021 and December 31, 2020, $0 and $316 was due to FECI, respectively. As of March 31, 2021, the Company has recorded a lease liability of $3,288 within Non-current lease liabilities on the condensed consolidated balance sheet.

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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 condensed consolidated financial statements. DevTech purchased 10% of a note payable due to an affiliate of the Company. As of March 31, 2021 and December 31, 2020, $715 was owed to DevTech on the note payable, and the outstanding note payable due to DevTech is included in Other long-term liabilities on the condensed consolidated balance sheets. The interest expense on the note payable due to DevTech was $21 and $19 for the three months ended March 31, 2021 and 2020, respectively. No interest has been paid, and accrued interest has been recognized within Other current liabilities on the condensed consolidated balance sheets. As of March 31, 2021 and December 31, 2020, $343 was due from DevTech.

Fortress affiliated entities

Since 2017, the Company has provided certain administrative services to related parties including Fortress affiliated entities. As of March 31, 2021 and December 31, 2020, $1,210 and $1,334 were due from affiliates, respectively. There are no costs incurred by the Company as the Company is fully reimbursed for all costs incurred. Beginning in the fourth quarter of 2020, the Company began to sublease a portion of office space to an affiliate of an entity managed by Fortress, and for the three months ended March 31, 2021, $153 of rent and office related expenses were incurred by this affiliate. As of March 31, 2021 and December 31, 2020, $359 and $204 were due from this affiliate, respectively.

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 $803 and $1,165 for the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, $3,160 and $2,657 were due to Fortress affiliated entities, respectively.

Due to/from Affiliates

The table below summarizes the balances outstanding with affiliates as of March 31, 2021 and December 31, 2020:

	March 31, 2021		December 31, 2020
Amounts due to affiliates	$	10,859	$	8,980
Amounts due from affiliates		1,912		1,881

21. Asset acquisitions

On January 12, 2021, the Company acquired 100% of the outstanding share quota of CH4 Energia Ltda. ("CH4"), an entity that owns key permits and authorizations to develop an LNG terminal and an up to 1.37GW gas-fired power plant at the Port of Suape in Brazil. The purchase consideration consisted of $903 of cash paid at closing in addition to potential future payments contingent on achieving certain construction milestones of up to $3,600. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments of $3,047 is included as part of the purchase consideration and is recognized in Other non-current liabilities on the condensed consolidated balance sheet as of March 31, 2021. The selling shareholders of CH4 may also receive future payments based on gas consumed by the power plant or sold to customers from the LNG terminal.

The purchase of CH4 has been accounted for as an asset acquisition. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $295 are included in the purchase consideration. The total purchase consideration of $4,245 was allocated to permits and authorizations acquired and is recorded within Intangible assets, net. In addition, the Company recognized a deferred tax liability of $1,531 that resulted from the acquisition.

On March 11, 2021, the Company acquired 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold grants to operate as an independent power provider and 15-year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil. The Company is seeking to obtain the necessary approvals to transfer the power purchase agreements in connection with the construction the gas-fired power plant and LNG import terminal at the Port of Suape.

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The purchase consideration consisted of $8,041 of cash paid at closing in addition to potential future payments contingent on achieving commercial operations of the gas-fired power plant at the Port of Suape of up to approximately $10.5 million. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments of $7,473 was included as part of the purchase consideration and is recognized in Other non-current liabilities on the condensed consolidated balance sheet as of March 31, 2021. The selling shareholders may also receive future payments based on power generated by the power plant in Suape, subject to a maximum payment of approximately $4.6 million.

The purchases of Pecém and Muricy were accounted for as asset acquisitions. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $1,275 were included in the purchase consideration. Of the total purchase consideration, $16,585 was allocated to acquired power purchase agreements and recorded in Intangibles on the condensed consolidated balance sheet; the remaining purchase consideration was related to working capital acquired.

22. Subsequent events

On April 12, 2021, the Company completed the private offering of $1.5 billion aggregate principal amount of senior secured notes due 2026 (the “2026 Notes”). The 2026 Notes bear interest at 6.50% per annum and were issued at an issue price equal to 100% of principal. The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes. The Company used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses.

On April 15, 2021, the Company completed the previously announced acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”); referred to as the “Hygo Merger” and “GMLP Merger,” respectively  and, collectively, the “Mergers”. NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger. NFE paid $3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interests of GMLP’s general partner, totaling $251 million. The Company also repaid certain outstanding debt facilities of GMLP in conjunction with closing the GMLP Merger.

These transactions will be accounted for as business combinations under the acquisition method of accounting. The Company will record the assets acquired and liabilities assumed at their fair values as of the acquisition date. Due to the limited time since the closing of the acquisitions, the valuation efforts and related acquisition accounting are incomplete at the time of filing of the condensed consolidated financial statements.

On April 15, 2021, we entered into a $200 million senior secured revolving facility (the “Revolving Facility”). The 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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Item 2.          Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Certain information contained in the following discussion and analysis, including information with respect to our plans, strategy, projections and expected timeline for our business and related financing, includes forward-looking statements. Forward-looking statements are estimates based upon current information and involve a number of risks and uncertainties. Actual events or results may differ materially from the results anticipated in these forward-looking statements as a result of a variety of factors.

You should read “Risk Factors” and “Cautionary Statement on Forward-Looking Statements” elsewhere in this Quarterly Report on Form 10-Q (“Quarterly Report”) and under similar headings in the Annual Report on Form 10-K for the year ended December 31, 2020 (our “Annual Report”) for a discussion of important factors that could cause actual results to differ materially from the results described in or implied by the forward-looking statements contained in the following discussion and analysis.

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

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

Overview

We are a global integrated gas-to-power infrastructure company that seeks to use natural gas to satisfy the world’s large and growing power needs. We deliver targeted energy solutions to customers around the world, thereby reducing their energy costs and diversifying their energy resources, while also reducing pollution and generating compelling margins. Our near-term mission is to provide modern infrastructure solutions to create cleaner, reliable energy while generating a positive economic impact worldwide. Our long-term mission is to become one of the world’s leading carbon emission-free independent power providing companies. We discuss this important goal in more detail in the Annual Report, “Items 1 and 2: Business and Properties” under “Toward a Carbon-Free Future”.

As an integrated gas-to-power energy infrastructure company, our business model spans the entire production and delivery chain from natural gas procurement and liquefaction to logistics, shipping, facilities and conversion or development of natural gas-fired power generation. 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 producer in Jamaica, and the Puerto Rico Electric Power Authority (“PREPA”), each of which is described in more detail below. Our assets built to service these significant customers have been designed with capacity to service other customers.

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

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

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 PPA. The CHP Plant also provides steam to Jamalco under a long-term take-or-pay SSA. On March 3, 2020, the CHP Plant commenced commercial operation under both the PPA and the SSA and began supplying power and steam to JPS and Jamalco, respectively. 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 San Juan Facility. The San Juan Facility is near the San Juan Power Plant and serves as our supply hub for the San Juan Power Plant and other industrial end-user customers in Puerto Rico. We have delivered natural gas used for the commissioning of PREPA’s power plant under the Fuel Sale and Purchase Agreement with PREPA since April 2020. See “—Other Matters” for additional information regarding our San Juan Facility.

Miami Facility

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.

Suape Development

On January 12, 2021, we acquired CH4 Energia Ltda., an entity that owns key permits and authorizations to develop an LNG terminal and up to 1.37GW of gas-fired power at the Port of Suape in Brazil. On March 11, 2021, we acquired 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“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 ANEEL and other relevant regulatory authorities in Brazil to transfer the site for the power purchase agreements to the Port of Suape and update the technical characteristics in order to develop and plan to construct a 288MW gas-fired power plant and LNG import terminal at the Port of Suape to provide LNG and natural gas to major energy consumers within the port complex and across the greater Northeast region of Brazil.

Other Development Projects

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

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

We are currently developing a modular floating liquefaction facility to provide a low-cost supply of liquefied natural gas for our growing customer base. The “Fast LNG” design pairs advancements in modular, midsize liquefaction technology with jack up rigs or similar floating infrastructure to enable a much lower cost and faster deployment schedule than today’s floating liquefaction vessels. A permanently moored FSU will serve as an LNG storage facility alongside the floating liquefaction infrastructure, which can be deployed anywhere there is abundant and stranded natural gas.

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Recent Developments: Hygo and GMLP Acquisitions

On April 15, 2021, the Company completed the previously announced acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”); referred to as the “Hygo Merger” and “GMLP Merger,” respectively and, collectively, the “Mergers”. NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger. NFE paid $3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interest of GMLP’s general partner, totaling $251 million.

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

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

Cash consideration for the GMLP Merger was funded from proceeds from a private offering of $1.5 billion aggregate principal amount of senior secured notes due 2026 (the “2026 Notes”) completed on April 12, 2021. The 2026 Notes bear interest at 6.50% per annum and were issued at an issue price equal to 100% of principal. On April 15, 2021, we also entered into a $200 million senior secured revolving facility (the “Revolving Facility”). The Revolving Facility has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.

COVID-19 Pandemic

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 three months ended March 31, 2021, we have incurred approximately $0.4 million for safety measures introduced into our operations and other responses to the COVID-19 pandemic.

We are actively monitoring the spread of the pandemic and the actions that governments and regulatory agencies are taking to fight the spread. We have not experienced significant disruptions in development projects and daily operations 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 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. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, have sought rehearing of the March 19, 2021 FERC order and such rehearing requests remain pending before FERC. FERC’s orders in the proceeding would be subject to subsequent judicial review.

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

	Three Months Ended March 31,
	2021			2020			Change
Revenues
Operating revenue	$	91,196		$	63,502		$	27,694
Other revenue		54,488			11,028			43,460
Total revenues		145,684			74,530			71,154
Operating expenses
Cost of sales		96,671			68,216			28,455
Operations and maintenance		16,252			8,483			7,769
Selling, general and administrative		45,181			28,538			16,643
Contract termination charges and loss on mitigation sales		-			208			(208	)
Depreciation and amortization		9,890			5,254			4,636
Total operating expenses		167,994			110,699			57,295
Operating loss		(22,310	)		(36,169	)		13,859
Interest expense		18,680			13,890			4,790
Other (income) expense, net		(604	)		611			(1,215	)
Loss on extinguishment of debt, net		-			9,557			(9,557	)
Loss before taxes		(40,386	)		(60,227	)		19,841
Tax (benefit)		(877	)		(4	)		(873	)
Net loss	$	(39,509	)	$	(60,223	)	$	20,714

Revenues

Operating revenue from the sale of LNG, natural gas or outputs from our natural gas-fired power generation facilities increased $27,694 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020. The increase was primarily driven by increases in volumes sold from the Old Harbour Facility, including volumes utilized in the CHP Plant which commenced commercial operations during March 2020:

• For the three months ended March 31, 2021, we recognized $51,644 of revenue from volumes sold at the Old Harbour Facility, as compared to $35,777 for the three months ended March 31, 2020, including additional revenue of $16,830 from natural gas utilized in the CHP Plant and Jamalco’s boilers. For the three months ended March 31, 2021, the volume delivered to the Old Harbour Facility was 53.0 million gallons (4.4 TBtu). For the three months ended March 31, 2020, the volume delivered to the Old Harbour Facility was 42.1 million gallons (3.5 TBtu). The increase in volumes from sales to the Old Harbour Facility was primarily due to volumes delivered to the CHP Plant and Jamalco’s boilers increasing by 15.7 million gallons (1.3 TBtu) to 25.5 million gallons (2.1 TBtu) from 9.8 million gallons (0.8 TBtu) in the three months ended March 31, 2020.

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

Operating revenue was also impacted by operations at our Montego Bay Facility. Sales at the Montego Bay Facility increased by $1,956 from $22,823 for the three months ended March 31, 2020 to $24,779 for the three months ended March 31, 2021. The increase in sales at the Montego Bay Facility was primarily due to an increase in sales to industrial end-user customers, offset by a minor decrease in consumption by the Bogue Power Plant. Volumes delivered at the Montego Bay Facility remained relatively consistent for the three months ended March 31, 2021 as compared to the three months ended March 31, 2021, increasing by 0.1 million gallons (0.0 TBtu) from 23.5 million gallons (2.0 TBtu) during the three months ended March 31, 2020 to 23.6 million gallons (2.0 TBtu) during the three months ended March 31, 2021.

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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 $43,460 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020, and the increases were due to an increase in revenue for development services in Puerto Rico for the three months ended March 31, 2021, including gas used by our customer for testing and commissioning their assets. Development services revenue recognized in the three months ended March 31, 2021 included $45,618 for the customer’s use of 48.7 million gallons (4.0 TBtu) of natural gas as part of commissioning their assets.  The increase was partially offset by a decrease in development services revenue of $1,033 related to conversion of the customer’s infrastructure within the San Juan Power Plant.

Cost of sales

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

Cost of LNG purchased from third parties for sale to our customers or delivered for commissioning of our customer’s assets in Puerto Rico increased $22,454 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020. The increase was primarily attributable to an 89% increase in volumes delivered, inclusive of volumes delivered from our Miami Facility, compared to the three months ended March 31, 2020, partially offset by the decrease in LNG cost. The weighted-average cost of LNG purchased from third parties and delivered decreased from $0.67 per gallon ($8.10 per MMBtu) for the three months ended March 31, 2020 to $0.51 per gallon ($6.17 per MMBtu) for the three months ended March 31, 2021. The weighted-average cost of our inventory balance as of March 31, 2021 and December 31, 2020 was $0.55 per gallon ($6.63 per MMBtu) and $0.40 per gallon ($4.81 per MMBtu), respectively.

Charter costs increased Cost of sales by $2,241 for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020. The increase was attributable to an additional vessel in our fleet associated with our San Juan Facility after our assets were placed in service in the third quarter of 2020, as well as credits received in the first quarter of 2020 that did not recur in the first quarter of 2021.

Operations and maintenance

Operations and maintenance includes costs of operating our Facilities, exclusive of costs to convert that are reflected in Cost of sales. Operations and maintenance for the three months ended March 31, 2021 was $16,252, which increased $7,769 from $8,483 for the three months ended March 31, 2020. The increase was primarily the result of operating facilities in the first quarter of 2021 that were still in development or had just commenced commercial operations in the first quarter of 2020. Operations and maintenance increased by the costs of operating the San Juan Facility of $3,206 and an increase in the cost to operate the CHP Plant of $1,844. Higher maintenance costs of $1,352 also contributed to the increased operations and maintenance costs for the three months ended March 31, 2021.

Selling, general and administrative

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

Selling, general and administrative for the three months ended March 31, 2021, was $45,181 which increased $16,643 from $28,538 for the three months ended March 31, 2020. The increase was primarily attributable to $11,563 of professional services costs and other costs associated with the Mergers. The increase was also attributable to $4,050 of higher payroll costs associated with increased headcount, partially offset by reductions to other administrative costs.

Contract termination charges and loss on mitigation sales

Loss on mitigation sales for the three months ended March 31, 2021 and 2020 was $0 and $208, respectively. In the first quarter of 2020, we incurred losses associated with undelivered quantities of LNG under firm purchase commitments due to storage capacity constraints. In these situations, our supplier will attempt to sell the undelivered quantity through a mitigation sale, and the losses incurred under the firm purchases are partially offset by this sale of the undelivered amount to third parties for amounts lower than the contracted price, which resulted in a loss of $208. We did not have such transactions during the three months ended March 31, 2021.

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Depreciation and amortization

Depreciation and amortization increased $4,636 for the three months ended March 31, 2021. The increase was primarily due to the following:

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

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

Interest expense

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

Other (income) expense, net

Other income, net for the three months ended March 31, 2021 was $604, which increased $1,215 from expense of $611 for the three months ended March 31, 2020, primarily as a result of the unrealized loss on our investment in equity securities of $2,400 in the first quarter of 2020 that did not recur in the first quarter of 2021. We also recognized income from the change in fair value of the derivative liability and equity agreement associated with our acquisition of Shannon LNG.

Loss on extinguishment of debt, net

Loss on extinguishment of debt for the three months ended March 31, 2020 was $9,557 as a result of the extinguishment of the Term Loan Facility in January 2020. We did not have such transactions during the three months ended March 31, 2021.

Tax (benefit)

We recognized a tax benefit for the three months ended March 31, 2021 of $877, compared to tax benefit of $4 for the three months ended March 31, 2020. The increase in benefit for the three months ended March 31, 2021 was primarily driven by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $3,010, partially offset by income tax expense recorded for certain profitable foreign operations. The Company determined that the valuation allowance should be released based on forecasted pre-tax profits in this jurisdiction.

During 2020, the CHP Plant began operations and we placed our assets at the San Juan Facility in service. Certain of our Jamaican operations had increased earnings for the three months ended March 31, 2021 as compared to the three months ended March 31, 2020 without any historical net operating losses to offset additional tax expense. During the third quarter of 2020, we placed our assets at the San Juan Facility into service, and since that point, we have recognized tax expense in Puerto Rico at a preferential tax rate due to our tax decree resulting in an effective tax rate lower than the U.S. federal income tax rate. We continue to have valuation allowances in many of our foreign jurisdictions and tax expense for earnings generated in many foreign jurisdictions has been limited.

Factors Impacting Comparability of Our Financial Results

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 three months ended March 31, 2021 include our Montego Bay Facility, Old Harbour Facility, San Juan Facility, certain industrial end-users and our Miami Facility. We are finalizing development of our La Paz Facility and our Puerto Sandino Facility, and our current results do not include revenue and operating results from these projects. Our current results also exclude other developments, including, but not limited to, potential developements in Brazil and the Ireland Facility.

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• Our historical financial results do not reflect new LNG supply agreements that will lower the cost of our LNG supply through 2030. We currently purchase the majority of our supply of LNG from third parties, sourcing approximately 97% of our LNG volumes from third parties for the three months ended March 31, 2021, a significant portion of which is under an LNG supply agreement signed in 2018. During 2020, we also entered into four LNG supply agreements for the purchase of approximately 415 TBtu of LNG at a price indexed to Henry Hub from 2021 and 2030, resulting in expected pricing below the pricing in our previous long-term supply agreement.

We also anticipate that the deployment of Fast LNG floating liquefaction facilities will significantly lower the cost of our LNG supply and reduce our dependence on third party suppliers.

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

Liquidity and Capital Resources

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

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

• In September 2020, we issued $1,000,000 of 2025 Notes and repaid all other outstanding debt. No principal payments are due on the 2025 Notes until maturity in 2025.

• In December 2020, we received proceeds of $263,125 from the issuance of $250,000 of additional notes on the same terms as the 2025 Notes (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein).

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

On April 12, 2021, we issued $1.5 billion of 2026 Notes. The 2026 Notes bear interest at 6.50% per annum and were issued at an issue price equal to 100% of principal. No principal payments are due on the 2026 Notes until maturity in 2026. The Company used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses. On April 15, 2021, we entered into the $200 million Revolving Facility that has a term of approximately five years and bears interest based on the three-month LIBOR rate plus certain margins.

We have assumed total expenditures for all completed and existing projects to be approximately $1,239 million, with approximately $839 million having already been spent through March 31, 2021. This estimate represents the expenditures necessary to complete the La Paz Facility and the Puerto Sandino Facility, expected expenditures to serve new industrial end-users and other planned capital expenditures. We expect to be able to fund all such committed projects with a combination of cash on hand, cash flows from operations and borrowings under our Revolving Facility. We may also seek to fund our developments through debt refinancings.  We are currently exploring the potential refinancing of the Golar Nanook with a sale-leaseback or similar financing.  We cannot assure whether any such refinancing will occur. Through March 31, 2021, we have spent approximately $144 million to develop the Pennsylvania Facility. Approximately $21 million of construction and development costs have been expensed as we have not issued a final notice to proceed to our engineering, procurement and construction contractors. Cost for land, as well as engineering and equipment that could be deployed to other facilities and associated financing costs of approximately $123 million, has been capitalized.

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Certain of the debt facilities of each of Hygo and GMLP or their respective subsidiaries remained outstanding following the closing of the Mergers.  The following is a description of the debt facilities for each of Hygo and GMLP that remain outstanding following the closing of the Mergers. In the future, we will need to repay or refinance this additional indebtedness which could adversely affect our liquidity and capital resources. There can be no assurances that we will be able to refinance this indebtedness on favorable terms or at all.

Hygo Debt

Sergipe Debt Financing

To finance construction of the Sergipe Facility and the Sergipe Power Plant, in April 2018, CELSE—Centrais Elétricas de Sergipe S.A. (“CELSE”) signed financing agreements with amounts made available by banks and multilateral organizations throughout 2018 and 2019 (the “CELSE Facility”). As of December 31, 2020, amounts outstanding and the effective interest rates under the CELSE Facility were as set forth below. Principal and interest payments are due each October and April, beginning October 2020. The CELSE Facility matures in April 2032.

Credit facility (Real and USD in millions)	Amount Outstanding		Effective interest rate
IFC	R$	844.9 ($156.8)	9.79	%
Inter-American Development Bank	R$	694.6 ($128.9)	9.69	%
IDB Invest	$	38.0	6.35	%
IDB China Fund	$	50.0	6.35	%

Also in April 2018, CELSE issued debentures in the aggregate principal amount of R$3,370.0 million (net proceeds of $874 million), due April 2032, bearing interest at a fixed rate of 9.85% (the “CELSE Debentures”). As of December 31, 2020, the balance of the CELSE Debentures was R$2,571.0 million ($477.3 million). Interest is payable on the CELSE Debentures semi-annually on each April 15 and October 15, beginning on October 15, 2018. The CELSE Debentures are amortized and repaid in 24 consecutive semi-annual installments on each of April 15 and October 15, commencing on October 15, 2020.

The indenture governing the CELSE Debentures contains covenants that: (i) requires CELSE to maintain a historical debt service coverage ratio for a twelve month period on or after March 31, 2021 of no less than 1.10 to 1.00; (ii) prohibit certain restricted payments; (iii) limit the ability of CELSE from creating any liens or incurring additional indebtedness; (iv) prohibit certain fundamental changes; (v) limit the ability of CELSE to transfer or purchase assets; (vi) prohibit certain affiliate transactions; (vii) limit the ability of CELSE to make change orders or give other directions under the documents related to the construction and operation of the project in certain circumstances; (viii) limit the ability of CELSE to enter into additional contracts; (ix) limit CELSE’s operating expenses and capital expenditures; and (x) prohibit CELSE from transferring, purchasing or otherwise acquiring any portion of the CELSE Debentures, other than pursuant to the exercise of the put option.

On April 12, 2018, CELSEPAR—Centrais Elétricas de Sergipe Participações S.A. (“CELSEPAR”) entered into a Standby Guarantee and Credit Facility Agreement with GE Capital EFS Financing, Inc. (“GE Capital”), as lender, and Ebrasil Energia Ltda. (“Ebrasil”) and Golar Power Brasil Participações S.A (“Golar Brazil”), each as sponsor (the “GE Credit Facility”). Pursuant to the GE Credit Facility, GE Capital agreed to provide $120.0 million in credit support in respect of CELSEPAR’s obligation to make certain contingent equity contributions to CELSE. Amounts disbursed under the GE Credit Facility accrue interest at a fixed rate of LIBOR plus a margin of 11.4% and are payable on May 30 and November 30 each year, beginning on May 30, 2021. The GE Credit Facility matures on November 30, 2024. As of December 31, 2020, there was R$689.4 million ($132.0 million) outstanding under the GE Credit Facility. The GE Credit Facility includes covenants and events of default that are customary for similar transactions.

Debenture Loan

On September 10, 2019, Hygo’s subsidiary, Golar Brazil issued debentures in the aggregate principal amount of R$300.0 million ($55.7 million) due September 2024, bearing interest at a rate equal to the one-day interbank deposit futures rate in Brazil plus 2.65% (the “Debentures”). The offering resulted in net proceeds to Golar Brazil, after deducting applicable discounts and commissions and offering expenses, of R$295.0 million ($54.8 million). Interest is payable on the Debentures semi-annually on each September 13 and March 13, beginning on September 13, 2020. Principal due under the Debentures is amortized semi-annually on each September 13 and March 13, beginning September 13, 2020.

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Golar Nanook Leaseback and Credit Facility

In September 2018, Golar FSRU8 Corp., a corporation organized in the Marshall Islands, as subsidiary of Hygo, entered into a sale and leaseback transaction with Compass Shipping 23 Corporation Limited in respect of the Golar Nanook (the “Nanook Leaseback”). In September 2018, Compass Shipping 23 Corporation Limited, the owner of the Golar Nanook, entered into a twelve-year, $277 million credit facility (the “Nanook Facility”). Although we have no control over the funding arrangements of Compass Shipping 23 Corporation Limited, we expect to be the primary beneficiary of the Golar Nanook and therefore expect to consolidate the Nanook Facility in our financial results. The Nanook Facility bears interest at LIBOR plus a margin equal to 3.5% and is repayable in a balloon payment on maturity. The Nanook Facility matures in September 2030.

The Golar Nanook is part of the Sergipe Facility.  The terminal’s assets consist of (i) our FSRU, the Golar Nanook, which is under a 25-year bareboat charter with CELSE (the “Sergipe FSRU Charter”), (ii) specialized mooring infrastructure and (iii) a dedicated 8 kilometer pipeline which connects to the adjacent Sergipe Power Plant. The Golar Nanook is financed through a twelve year sale-leaseback transaction with the right and obligation to repurchase the vessel at the end of the lease period. The balance of the infrastructure as well as our interest in the Sergipe Power Plant is owned through our joint venture, CELSEPAR.

The Golar Nanook operates under a 25-year bareboat charter with CELSE (the “Sergipe FSRU Charter”).  Pursuant to the Sergipe FSRU Charter, the Golar Nanook generates approximately $44 million per year in bareboat charter earnings, indexed to the Consumer Price Index (“CPI”), with operating expenditures passed through to CELSE.

Pursuant to the terms of the Sergipe FSRU Charter, we expect total revenues less estimated operating costs, without adjusting for inflation, of $1.1 billion over the 25-year term. The charter terminates on December 31, 2044. In addition to the charter, we expect to generate incremental revenue in the Sergipe Facility from downstream customers. The Sergipe Facility is capable of processing up to 790,000 MMBtu/d and storing up to 170,000 cubic meters of LNG. We expect the terminal to utilize approximately 230,000 MMBtu/d (30% of the terminal’s maximum regasification capacity) to provide natural gas to the Sergipe Power Plant at full dispatch.

CELSE has executed multiple PPAs pursuant to which the Sergipe Power Plant will deliver power to 26 committed offtakers, including investment grade counterparties, for a period of 25 years. These PPAs provide for guaranteed annual capacity payments of R$1.6 billion at an expected contracted EBITDA margin on gross revenue of 61% (calculated as total revenues less direct operating expenditures (including typical G&A and O&M charges relating to such arrangements) assuming zero dispatch and subject to standard adjustments for inflation and taxes to be incurred). The fixed capacity payments are adjusted annually for the Extended National Consumer Price Index (the “IPCA”), the Brazilian inflation-targeting system, which has historically offset changes in the exchange rate between the U.S. dollar and the Brazilian real. Annual revenues less operating costs are expected to be R$1.1 billion. Based on the terms of our PPAs, we expect total contracted revenues over the 25-year term, without adjusting for inflation, of R$41.0 billion. We also expect to generate incremental variable revenue during periods we elect to dispatch and sell power from the facility.

Golar Penguin Leaseback and Credit Facility

In December 2019, Golar Hull M2023 Corp., a corporation organized in the Marshall Islands, as subsidiary of Hygo, entered into a sale and leaseback transaction with Oriental LNG 02 Limited in respect of the Golar Penguin (the “Penguin Leaseback”). Payments are due quarterly in 24 installments of $1.89 million, with a balloon payment of approximately $68.0 million upon maturity. The Penguin Leaseback also contains certain covenants that, among other things, (i) require GLNG to maintain a consolidated net worth equal or greater to $450.0 million and maintain current assets equal to or greater than current liabilities and (ii) require the guarantor to maintain free liquid assets with aggregate value equal to or greater than $50.0 million. The Penguin Leaseback is cross-collateralized with a vessel under a sale and leaseback transaction between a subsidiary of GLNG and Oriental LNG 01 Limited, whereby a default under one sale and leaseback transaction automatically results in a default under the other. In connection with the Hygo Merger, a Supplemental Deed to the Penguin Leaseback was executed pursuant to which the cross-collateralization and related default were removed. The Supplemental Deed is effective subject to certain conditions, including consent from the lenders to the Penguin Facility (as defined below) set out therein.

In October 2020, Oriental LNG 02 Limited, the owner of the Golar Penguin, entered into a financing agreement to refinance its existing $113.4 million loan facility (the “Penguin Facility”). Although we have no control over the funding arrangements of Oriental LNG 02 Limited, we expect to be the primary beneficiary of the Golar Penguin and therefore expect to be required to consolidate the Penguin Facility in our financial results. The Penguin Facility bears interest at LIBOR plus a margin of 1.7% and is repayable in quarterly installments over a term of approximately six years.

Golar Celsius Leaseback and Credit Facility

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

In March 2020, Noble Celsius Shipping Limited, the owner of the Golar Celsius, entered into a three-year loan facility for $118.2 million (the “Celsius Facility”). The Celsius Facility is denominated in U.S. dollars and bears interest at 4.0% and is repayable at the end of the three-year period. Although we have no control over the funding arrangements of Noble Celsius Shipping Limited, we expect to be the primary beneficiary of the Golar Celsius and therefore expect to consolidate the Celsius Facility in our financial results.

GMLP Debt

Golar Eskimo Leaseback and Credit Facility

In November 2015, GMLP entered into a sale and leaseback transaction with a subsidiary, Sea 23 Leasing Co. Limited (“Eskimo SPV”) of China Merchants Bank Leasing in respect of the Golar Eskimo (the “Eskimo Leaseback”). The Eskimo Leaseback also contains certain covenants that, among other things and subject to certain exceptions and qualifications require: (a) GMLP to maintain a minimum level of liquidity of $30 million and consolidated net worth of $123.95 million, (b) GMLP to not exceed a maximum net debt to EBITDA ratio of 6.5:1, (c) GMLP to maintain a minimum percentage of the value of the Golar Eskimo over the relevant outstanding balances of 110%. The Eskimo Leaseback is cross-collateralized with a vessel under a sale and leaseback transaction between a subsidiary of GLNG and Sea 24 Leasing Co. Limited, whereby a default under one sale and leaseback transaction automatically results in a default under the other.

In November 2015, Eskimo SPV, which is the legal owner of the Golar Eskimo, entered into a long-term loan facility (the “Eskimo SPV Debt”). The facility bears interest at a rate of LIBOR plus a margin. Although we have no control over the funding arrangements of the Eskimo SPV, we will be the primary beneficiary of the Golar Eskimo and therefore will be required to consolidate the Eskimo SPV Debt in our financial results.

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

Golar Hilli Leaseback

Golar Hilli Corporation (“Hilli Corp”) is a party to a Memorandum of Agreement, dated September 9, 2015, with Fortune Lianjiang Shipping S.A., a subsidiary of China State Shipbuilding Corporation (“Fortune”), pursuant to which Hilli Corp has sold to and leased back from Fortune the Hilli under a 10-year bareboat charter agreement (the “Hilli Leaseback”). GMLP’s 50% share of Hilli Corp’s indebtedness of $778.5 million amounted to $389.3 million as of December 31, 2020.

Pursuant to the GMLP Guarantee, GMLP is required to comply with the following covenants and ratios: (i) free liquid assets of at least $30 million throughout the Hilli Leaseback period; (ii) a maximum net debt to EBITDA ratio for the previous 12 months of 6.5:1; (iii) a consolidated tangible net worth of $123.95 million, and (iv) a minimum EBITDA to consolidated debt service for the previous 12 months of 1.20:1.

Series A Preferred Units

Distributions on the Preferred Units are payable out of amounts legally available therefor at a rate equal to 8.75% per annum of the stated liquidation preference. In the event of a liquidation, dissolution or winding up, whether voluntary or involuntary, holders of Preferred Units will have the right to receive a liquidation preference of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of payment, whether declared or not. At any time on or after October 31, 2022, the Preferred Units may be redeemed, in whole or in part, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon on the date of redemption, whether declared or not.

Cash Flows

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

	Three Months Ended March 31,
(in thousands)	2021			2020			Change
Cash flows from:
Operating activities	$	(111,986	)	$	(51,311	)	$	(60,675	)
Investing activities		(90,257	)		(56,048	)		(34,209	)
Financing activities		(47,891	)		305,589			(353,480	)
Net (decrease) increase in cash, cash equivalents, and restricted cash	$	(250,134	)	$	198,230		$	(448,364	)

Cash (used in) operating activities

Our cash flow used in operating activities was $111,986 for the three months ended March 31, 2021, which increased by $60,675 from $51,311 for the three months ended March 31, 2020. The increase in cash flow used in operating activities for the three months ended March 31, 2021 was due to unfavorable changes in working capital accounts, primarily significant increases in receivables, inventory and decrease to accounts payable and accrued liabilities. In total changes in these working capital accounts resulted in $46,793 of additional cash used in operating activities in the first quarter of 2021.

Cash (used in) investing activities

Our cash flow used in investing activities was $90,257 for the three months ended March 31, 2021, which increased by $34,209 from $56,048 for the three months ended March 31, 2020. Cash outflows for investing activities during the three months ended March 31, 2021 were primarily used for development projects in Nicaragua and Mexico.

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

Cash (used in) provided by financing activities

Our cash flow used in financing activities was $47,891 for the three months ended March 31, 2021, which decreased by $353,480 from cash provided by financing activities of $305,589 for the three months ended March 31, 2020. Cash used in financing activities during the three months ended March 31, 2021 was due to payments of $29,564 related to tax withholdings for share-based compensation, as well as dividends paid of $17,657.

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Cash flow provided by financing activities during the three months ended March 31, 2020 was primarily due to borrowings under the Credit Agreement of $800,000, partially offset by an original issue discount of $20,000 and transaction costs and other fees to obtain the Credit Agreement of $14,069. A portion of these proceeds was used to fund the repayment of the Term Loan Facility of $506,402. Additionally, the remaining proceeds from the Senior Secured Bonds of $52,144 were received during the first quarter of 2020.

Long-Term Debt

2025 Notes

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

The 2025 Notes are guaranteed, jointly and severally, by certain of our subsidiaries, in addition to other collateral. The 2025 Notes may limit our ability to incur additional indebtedness or issue certain preferred shares, make certain payments, and sell or transfer certain assets subject to certain financial covenants and qualifications. The 2025 Notes also provide for customary events of default and prepayment provisions.

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

In connection with the issuance of the 2025 Notes, we incurred $17,937 in origination, structuring and other fees. Issuance costs of $13,909 were deferred as a reduction of the principal balance of the 2025 Notes on the condensed consolidated balance sheets; unamortized deferred financing costs related to lenders in our prior credit agreement that participated in the 2025 Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes. As a portion of the repayment of the prior credit agreement was a modification, in the third quarter of 2020 we recorded $4,028 of third-party fees in Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss.

On December 17, 2020, the Company issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,436. As of March 31, 2021, total remaining unamortized deferred financing costs were $10,201.

2026 Notes

On April 12, 2021, the Company issued $1.5 billion of 2026 Notes. The 2026 Notes bear interest at a rate of 6.50% per annum, payable semi-annually in arrears on March 31 and September 30 of each year, commencing on September 30, 2021. The 2026 Notes will mature on September 30, 2026 and may be redeemed earlier by the Company, subject to certain “make-whole” premiums.

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

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

Revolving Facility

On April 15, 2021, the Company entered into the Revolving Facility. The proceeds of the Revolving Facility may be used for working capital and other general corporate purposes (including permitted acquisitions and other investments). Letters of credit issued under the $100 million letter of credit sub-facility may be used for general corporate purposes. The Revolving Facility will mature in 2026, with the potential for the Company to extend the maturity date once in a one-year increment.

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Borrowings under the Revolving Facility will bear interest at a per annum rate equal to LIBOR plus 2.50% if the usage under the Revolving Facility is equal to or less than 50% of the commitments under the Revolving Facility and LIBOR plus 2.75% if the usage under the Revolving Facility is in excess of 50% of the commitments under the Revolving Facility, subject in each case to a 0.00% LIBOR floor. Borrowings under the Revolving Facility may be prepaid, at the option of the Company, at any time without premium.

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

Off Balance Sheet Arrangements

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

Contractual Obligations

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

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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 began to receive these ISO tanks and the lease terms commenced during the second quarter of 2021. The lease term for each of these leases is five years, and expected payments under these lease agreements have been included in the above table.

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

Summary of Critical Accounting Estimates

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.

Revenue recognition

Our contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam which are outputs from our natural gas-fueled infrastructure. The transaction price for each of these contracts is structured using similar inputs and factors regardless of the output delivered to the customer. 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 condensed 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 condensed 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 condensed 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 condensed consolidated statements of operations and comprehensive loss.

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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.

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 decreases throughout 2019 and 2020. Due to the decline in LNG prices, we executed four long-term LNG supply agreements in 2020 at prices that are expected to be significantly lower than inventory purchased under our contract with our current supplier. Further, we were able to take advantage of the lower market pricing for LNG to supply our operations for the second half of 2020, resulting in an overall lower average cost of LNG. Our long-term, take-or pay contracts to deliver natural gas or LNG to our customers also limit our exposure to fluctuations in natural gas and LNG as our pricing is based on the Henry Hub index plus a contractual spread. 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 been significantly impacted by responses to the COVID-19 pandemic to date. We will continue to monitor this uncertain situation and local responses in jurisdictions where we do business to determine if there are any indicators that a recoverability assessment for our assets should be performed.

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

When performing a recoverability assessment, 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 March 31, 2021, management determined that it was not probable that the performance condition for our outstanding PSUs would be met. For these awards, compensation cost and the number of PSUs ultimately earned remains variable and compensation cost for these awards is recorded once achievement of the performance conditions becomes probable through the requisite service period. A cumulative adjustment to share-based compensation expense is recorded in the period that achievement of performance conditions becomes probable.

Recent Accounting Standards

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

Item 3. Quantitative and Qualitative Disclosures About Market Risks.

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 2025 Notes were issued with a fixed rate of interest, and as such, a change in interest rates would impact the fair value of the 2025 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 $50 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.

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Item 4. 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 March 31, 2021. 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 March 31, 2021 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 the quarter ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II

OTHER INFORMATION

Item 1. 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 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 Hygo and its subsidiaries, and including GMLP and its subsidiaries. References to “Hygo” and “GMLP”, respectively, in this section, refer to Hygo and GMLP and their respective subsidiaries, along with the Company and its subsidiaries.

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 Mergers

• We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers;

• We may not have discovered undisclosed liabilities of either Hygo or GMLP during our due diligence process, and we may not have adequate legal protection from potential liabilities of, or in respect of our acquisitions of, Hygo and GMLP;

• We have incurred 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 Mergers;

Risks Related to Our Business

• 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;

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

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

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

• 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;

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

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

• Information technology failures and cyberattacks could affect us significantly;

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

• 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;

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

• 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;

• 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;

• Our business could be affected adversely by labor disputes, strikes or work stoppages in Brazil;

• 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

• 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

• Hygo’s Sergipe Facility is not currently operating at full capacity while equipment is being repaired, and we do not know the precise date when the facility will resume operations at full capacity. Once operations fully resume, the facility will be subject to customary operational risk for facilities of this type. Hygo’s other planned facilities are in various stages of contracting, construction, permitting and commissioning, each of which may present challenges to completion;

• 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 contingencies;

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

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

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

Risks Related to GMLP Business Activities

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

• 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;

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

• 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

• 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; and

• 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.

Risks Related to the Mergers

Uncertainties associated with the 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. Now that the Mergers have been completed, our success depends in part upon on our ability to attract, motivate and retain key management personnel and other key employees. 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 now that the Mergers have been completed.

We may be unable to successfully integrate the businesses and realize the anticipated benefits of the Mergers.

The success of the Mergers will depend, in part, on our ability to successfully combine each of Hygo and GMLP, which recently operated 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 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 Mergers.

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The 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:

• managing a larger company;

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

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

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

• consolidating corporate and administrative infrastructures and eliminating duplicative operations;

• coordinating geographically separate organizations;

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

• unanticipated changes in federal or state laws or regulations.

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, and we may not have adequate legal protection from potential liabilities of, or in respect of our acquisition of, Hygo and GMLP.

In the course of the due diligence review of each of Hygo and GMLP that we conducted prior to the consummation of each of the Mergers, 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. Moreover, we may not have adequate legal protection from potential liabilities of, or in respect of our acquisition of, Hygo or GMLP, irrespective of whether such potential liabilities were discovered or not. Examples of such undisclosed or potential liabilities or other issues may include, but are not limited to, pending or threatened litigation, regulatory matters, tax liabilities, indemnification of obligations, undisclosed counterparty termination rights, or undisclosed letter of credit or guarantee requirements. Any such undisclosed or potential liabilities or other issues could have an adverse effect on our business, results of operations, financial condition and cash flows.

We have  incurred 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 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. 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.

In addition, in connection with both the Hygo Merger and the GMLP Merger, we assumed a significant amount of indebtedness, including guarantees and preferred shares. As such, we are now 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.

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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 not be able to convert our anticipated LNG pipeline into binding contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate.

We are actively pursuing a significant number of new LNG contracts with multiple counterparties in multiple jurisdictions.  Potential sales contracts may differ meaningfully depending on various factors, including, but not limited to: whether the potential customer is a government entity or a private party; whether the contract process is done pursuant to a public bidding process or a bilateral negotiation; the infrastructure and permits needed for a particular project; customer timing requirements and applicable laws.  Moreover, counterparties commemorate their commitment to purchase LNG in various degrees of formality ranging from traditional contracts to less formal arrangements.

Given the variety of sales processes and counterparty acknowledgements of the LNG volumes they will purchase, we sometimes identify potential sales volumes as being either “Committed” or “In Discussion.”  “Committed” volumes generally refer to the volumes that management expects to be sold under binding contracts, non-binding letters of intent or memorandums of understanding.  “In Discussion” volumes generally refer to volumes that management is actively bidding on, responding to a request for proposals for or is actively negotiating.

Management’s estimations of “Committed” and “In Discussion” volumes may prove to be incorrect.  We may never sign a binding agreement to sell LNG to the counterparty, or we may sell much less LNG than we estimate.  Accordingly, we cannot assure you that Committed or In Discussion volumes will result in actual sales, and such volumes should not be used to predict the company’s future results.

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 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:

• 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;

• failure to develop cost-effective logistics solutions;

• failure to manage expanding operations in the projected time frame;

• 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;

• 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.”);

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

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

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

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

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

• failure to anticipate and adapt to new trends in the energy sector in the U.S., Jamaica, the Caribbean, Mexico, Ireland, Nicaragua, Brazil and elsewhere;

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

• 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;

• 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;

• 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;

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

• 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;

• 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

• 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.

Our Fast LNG strategy is innovative and thus not yet proven.  We may not be able to realize the time and cost savings we expect to achieve with our Fast LNG strategy.

We have developed our Fast LNG strategy to procure and deliver LNG to our customers more quickly and cost-effectively than traditional LNG procurement and delivery strategies used by other market participants.  We are in the process of designing and constructing our first Fast LNG solution.  The Fast LNG technology may take more time and money to construct than we currently estimate.  We may not be able to successful construct our Fast LNG solution, and even if we succeed in constructing the technology, we may ultimately not be able to realize the time and cost savings we currently expect to achieve from this strategy.  Any such failure could negatively affect both the timing and costs of some future projects, impair our ability to reduce our future LNG costs and negatively affect our financial results.

We may not be able to convert our anticipated LNG pipeline into binding contracts, and if we fail to convert potential sales into actual sales, we will not generate the revenues and profits we anticipate.

We are actively pursuing a significant number of new LNG contracts with multiple counterparties in multiple jurisdictions.  Potential sales contracts may differ meaningfully depending on various factors, including, but not limited to: whether the potential customer is a government entity or a private party; whether the contract process is done pursuant to a public bidding process or a bilateral negotiation; the infrastructure and permits needed for a particular project; customer timing requirements and applicable laws.  Moreover, counterparties commemorate their commitment to purchase LNG in various degrees of formality ranging from traditional contracts to less formal arrangements.

Given the variety of sales processes and counterparty acknowledgements of the LNG volumes they will purchase, we sometimes identify potential sales volumes as being either “Committed” or “In Discussion.”  “Committed” volumes generally refer to the volumes that management expects to be sold under binding contracts, non-binding letters of intent or memorandums of understanding.  “In Discussion” volumes generally refer to volumes that management is actively bidding on, responding to a request for proposals for or is actively negotiating.

Management’s estimations of “Committed” and “In Discussion” volumes may prove to be incorrect.  We may never sign a binding agreement to sell LNG to the counterparty, or we may sell much less LNG than we estimate.  Accordingly, we cannot assure you that Committed or In Discussion volumes will result in actual sales, and such volumes should not be used to predict the company’s future results.

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. See “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Quarterly Report for more information on our outstanding indebtedness. 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 March 31, 2021. 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 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, the Sergipe Facility 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.

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.

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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.

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:

• upon the occurrence of certain events of force majeure;

• if we fail to make available specified scheduled cargo quantities;

• the occurrence of certain uncured payment defaults;

• the occurrence of an insolvency event;

• the occurrence of certain uncured, material breaches; and

• 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:

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

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

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

• insufficient LNG tanker capacity;

• weather conditions and natural disasters;

• reduced demand and lower prices for natural gas;

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

• 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;

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

• 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;

• 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;

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

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

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.

As more fully discussed in our Annual Report and elsewhere in this Quarterly Report, 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.

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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.

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 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.

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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 decisions with respect to Hygo’s Barcarena Facility (as defined herein) and Santa Catarina Facility (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.

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 “Item 1A. Risk Factors.” 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, the Barcarena Facility, the Santa Catarina Facility 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:

• 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;

• 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;

• 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;

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

• 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;

• 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;

• 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

• 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.

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, the Sergipe Facility, the Barcarena Facility and the Santa Catarina Facility, 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:

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

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

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

• attract, develop and retain skilled personnel, including engineers;

• post required construction bonds and comply with the terms thereof;

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

• 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.

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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.

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.

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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:

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

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

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

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

• decreases in the cost of competing sources of natural gas, LNG or alternate fuels such as coal, heavy fuel oil and automotive diesel oil (“ADO”)

• decreases in the price of LNG; and

• 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 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 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.

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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 awarded an 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.

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.

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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.

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:

• natural disasters;

• mechanical failures;

• grounding, fire, explosions and collisions;

• piracy;

• human error; and

• 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:

• marine disasters;

• piracy;

• bad weather;

• mechanical failures;

• environmental accidents;

• grounding, fire, explosions and collisions;

• human error; and

• war and terrorism.

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

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

• delays in the delivery of cargo;

• loss of revenues;

• termination of charter contracts;

• governmental fines, penalties or restrictions on conducting business;

• higher insurance rates; and

• 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 remain relevant following the 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.

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.

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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:

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

• political or economic disturbances in the countries where the tankers are being constructed;

• changes in governmental regulations or maritime self-regulatory organizations;

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

• bankruptcy or other financial crisis of shipbuilders;

• quality or engineering problems;

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

• 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.

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.

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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:

• expected supply is less than the amount hedged;

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

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

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.

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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.

Our business could be affected adversely by labor disputes, strikes or work stoppages in Brazil

All of our employees in Brazil are represented by a labor union and are covered by collective bargaining agreements pursuant to Brazilian labor legislation. As a result, we are subject to the risk of labor disputes, strikes, work stoppages and other labor-relations matters. We could experience a disruption of our operations or higher ongoing labor costs, which could have a material adverse effect on our operating results and financial condition. Future negotiations with the unions or other certified bargaining representatives could divert management attention and disrupt operations, which may result in increased operating expenses and lower net income. Moreover, future agreements with unionized and non-unionized employees may be on terms that are note as attractive as our current agreements or comparable to agreements entered into by our competitors. Labor unions could also seek to organize some or all of our non-unionized workforce.

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.

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.

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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.

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 and could have a material adverse effect on us.

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. On March 19, 2021 FERC issued an order that the San Juan Facility does fall under FERC jurisdiction. FERC directed us to file an application for authorization to operate the San Juan Facility within 180 days of the order, but also found that allowing operation of the San Juan Facility to continue during the pendency of an application is in the public interest. FERC also concluded that no enforcement action against us is warranted, presuming we comply with the requirements of the order. Parties to the proceeding, including the Company, have sought rehearing of the March 19, 2021 FERC order and such rehearing requests remain pending before FERC. FERC’s orders in the proceeding would be subject to subsequent judicial review.

We cannot control the outcome of any review or 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.

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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.

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.

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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 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, Brazil, 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, Brazil 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:

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

• change in applicable laws;

• an increase in oil, natural gas or petrochemical prices;

• devaluation of the applicable currency;

• higher inflation; or

• 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 condensed 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, 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 with BR Distribuidora, which could adversely impact 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 Facility. 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 contingencies.

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:

• the amount of LNG or natural gas sold to customers;

• market price of LNG;

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

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

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

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

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

• 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, and the plant is not currently operating. 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.

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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.

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, 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 Facilities 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.

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

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

• due to inflexibility or necessity of the generator;

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

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

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

• 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 Facility, the Santa Catarina Facility, 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.

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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.

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 have entered into management agreements with GLNG or its affiliates with respect to Hygo’s vessels. 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, it could have a material adverse effect on 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 Limited (“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 Facility. 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.

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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.

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.

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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

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:

• warnings;

• 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);

• prohibition on operations;

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

• restrictions on the operation of existing facilities and projects; or

• 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.

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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.

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.

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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:

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

• 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.

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 at which 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.

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If GMLP loses any of its charterers and is 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. 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:

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

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

• the quality and experience of its seafaring crew;

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

• its relationships with shipyards and construction management experience; and

• 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.

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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.

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, financial condition and operating results.

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:

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

• 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;

• 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;

• incur or assume unanticipated liabilities, losses or costs;

• 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;

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

• 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. In connection with the consummation of the GMLP acquisition, NFE will enter into a letter of undertaking pursuant to which we will guarantee GMLP’s obligations with respect to its guarantee of Hilli Corp’s debt under the Hilli Leaseback to the extent GMLP does not perform thereunder.

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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.

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. 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.

• 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.

• 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.

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:

• prevailing economic conditions in the natural gas and energy markets;

• a substantial or extended decline in demand for LNG;

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

• the size and age of a vessel; and

• 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 does 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, and financial condition.

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, or operating results.

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.

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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.

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 cash flows.

Risks Related to Ownership of Our Class A Common Stock

The Mergers 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 Mergers will be accretive to earnings per share (on an as adjusted earnings basis that is not pursuant to GAAP) from and after the 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, certain other amounts to be paid in connection with the Mergers may cause dilution to our earnings per share or decrease or delay the expected accretive effect of the Mergers and cause a decrease in the market price of our common stock. 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 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 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:

• a shift in our investor base;

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

• actual or anticipated fluctuations in our operating results;

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

• 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;

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

• the operating and share price performance of other comparable companies;

• overall market fluctuations;

• general economic conditions; and

• 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 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 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 Mergers as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the 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 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.

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”) and affiliates of Fortress Investment Group LLC 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 NFE SMRS Holdings LLC are parties to the Shareholders’ Agreement and as of April 23, 2021 hold approximately 16.8% 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 April 23, 2021, affiliates of the Founder Entities own an aggregate of approximately 112,223,619 shares of Class A common stock, representing 54.3% of our voting power. As of April 23, 2021, Wesley R. Edens, Randal A. Nardone and Fortress Investment Group LLC directly or indirectly own 72,627,776 shares, 26,196,526 shares and 13,399,317 shares, respectively, of our Class A common stock, representing 35.1%, 12.7% and 6.5% 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.

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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.

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:

• 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;

• 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

• 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.

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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.

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.

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 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 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.

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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.

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.

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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.

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.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

As of April 15, 2020, GLNG pledged, hypothecated or granted security interests in all of its shares of our common stock pursuant to a pledge agreement on a non-recourse basis. The pledge agreement contains customary default provisions and that in the event of a default under the pledge agreement, the secured parties may foreclose upon any and all shares of our common stock pledged to them.

The Company did not independently verify the foregoing disclosure. The Company is not a party to the pledge agreement and will have not have any obligations thereunder. The Company did deliver customary letter agreements to the secured parties in which it will, among other things, agree, subject to applicable law and stock exchange rules, not to take any actions that are intended to materially hinder or delay the exercise of any remedies by the secured parties under the pledge agreement.

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Item 6. Exhibits.

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 SEC 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 SEC 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 SEC 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 SEC 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 SEC 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 SEC on February 5, 2019).
3.4	Certificate of Conversion of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.1 to the Registrant’s Form 8-K filed with the SEC on August 7, 2020).
3.5	Certificate of Incorporation of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.2 to the Registrant’s Form 8-K filed with the SEC on August 7, 2020).
3.6	Bylaws of New Fortress Energy Inc. (incorporated by reference to Exhibit 3.3 to the Registrant’s Form 8-K filed with the SEC on August 7, 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 SEC 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 SEC 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 SEC 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 SEC on December 24, 2018).
10.5†	Form of Employee Restricted Share Unit Award Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q (File No. 001- 38790), filed with the Commission on May 15, 2019).
10.6	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 SEC on February 5, 2019).
10.7	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 SEC on February 5, 2019).
10.8†	Indemnification Agreement (Edens) (incorporated by reference to Exhibit 10.4 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).

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10.9†	Indemnification Agreement (Guinta) (incorporated by reference to Exhibit 10.5 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.10†	Indemnification Agreement (Catterall) (incorporated by reference to Exhibit 10.7 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.11†	Indemnification Agreement (Grain) (incorporated by reference to Exhibit 10.8 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.12†	Indemnification Agreement (Griffin) (incorporated by reference to Exhibit 10.9 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.13†	Indemnification Agreement (Mack) (incorporated by reference to Exhibit 10.10 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.14†	Indemnification Agreement (Nardone) (incorporated by reference to Exhibit 10.11 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.15†	Indemnification Agreement (Wanner) (incorporated by reference to Exhibit 10.12 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.16†	Indemnification Agreement (Wilkinson) (incorporated by reference to Exhibit 10.13 to the Registrant’s Form 8-K (File No. 001-38790), filed with the SEC on February 5, 2019).
10.17	Amendment Agreement dated as February 11, 2019 to Credit Agreement, dated as of August 15, 2018 and as amended and restated as of December 31, 2018, among New Fortress Intermediate LLC, NFE Atlantic Holdings LLC, the subsidiary guarantors from time to time party thereto, lenders parties thereto and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.25 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019).
10.18	Second Amendment Agreement, dated as of March 13, 2019 to the Credit Agreement, dated as of August 15, 2018 and as amended and restated as of December 31, 2018, and as amended as of February 11, 2019, among New Fortress Intermediate LLC, NFE Atlantic Holdings LLC, the subsidiary guarantors from time to time party thereto, lenders parties thereto and Morgan Stanley Senior Funding, Inc., as administrative agent (incorporated by reference to Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K, filed with the SEC on March 26, 2019).
10.19	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 SEC on January 25, 2019).
10.20†	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, filed with the SEC on March 26, 2019).
10.21	Letter Agreement, dated as of December 3, 2019, by and between NFE Management LLC and Yunyoung Shin. (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q, filed with the SEC on May 6, 2020)
10.22	Indenture, dated September 2, 2020, by and among the Company, 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, filed with the SEC on September 2, 2020).
10.23	Pledge and Security Agreement, dated September 2, 2020, by and among the Company, the subsidiary guarantors from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on September 2, 2020).
10.24	First Supplemental Indenture, dated December 17, 2020, by and among the Company, 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, filed with the SEC on December 18, 2020).
10.25	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 SEC on January 20, 2021)
10.26	Indenture, dated April 12, 2021, by and among the Company, 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, filed with the SEC on April 12, 2021).

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10.27	Pledge and Security Agreement, dated April 12, 2021, by and among the Company, the subsidiary guarantors, from time to time party thereto, and U.S. Bank National Association, as notes collateral agent (incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 12, 2021).
10.28	Shareholders’ Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and Stonepeak (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021).
10.29	Credit Agreement, dated as of April 15, 2021, by and among the Company, as the borrower, the guarantors from time to time party thereto, the several lenders and issuing banks from time to time party thereto, and  Morgan Stanley Senior Funding, Inc,. as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, filed with the SEC on April 21, 2021).
10.30*	Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GLNG and certain other parties thereto.
10.31*	Indemnity Agreement, dated as of April 15, 2021, by and among the Company, GLNG, and certain affiliates of Stonepeak.
10.32*	Omnibus Agreement, dated as of April 15, 2021, by and among the Company, GMLP, GLNG and certain parties thereto.
10.33*	Indemnification Agreement, dated as of April 15, 2021, by and between NFE International and GLNG
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.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
104*	Cover Page Interactive Data File, formatted in Inline XBRL and contained in Exhibit 101

* Filed as an exhibit to this Quarterly Report

** Furnished as an exhibit to this Quarterly Report

† Compensatory plan or arrangement

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SIGNATURES

Pursuant to the requirements 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: May 7, 2021
	By:	/s/ Wesley R. Edens
	Name:	Wesley R. Edens
	Title:	Chief Executive Officer and Chairman
		(Principal Executive Officer)
Date: May 7, 2021

	By:	/s/ Christopher S. Guinta
	Name:	Christopher S. Guinta
	Title:	Chief Financial Officer
		(Principal Financial Officer)
Date: May 7, 2021

By:	/s/ Yunyoung Shin
Name:	Yunyoung Shin
Title:	Chief Accounting Officer
	(Principal Accounting Officer)

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EX-10.30

Exhibit 10.30

Execution Version

OMNIBUS AGREEMENT

THIS OMNIBUS AGREEMENT (this “Agreement”) is entered into as of April 15, 2021 by and between the Parties (as set out in Schedule D).

R E C I T A L S:

1.          On January 13, 2021, Hygo Energy Transition Ltd., a Bermuda exempted company (the “Company”), entered into an agreement and plan of merger (the “Merger Agreement”) with Golar LNG Limited, a Bermuda exempted company, Stonepeak Infrastructure Fund II Cayman (G) Ltd., New Fortress Energy Inc., a Delaware corporation (“Parent”), and Lobos Acquisition Ltd., a Bermuda exempted company and an indirect, wholly-owned Subsidiary of Parent (“Merger Sub”).

2.          Pursuant to the Merger Agreement, at the Effective Time (as such term is defined in the Merger Agreement), Merger Sub merged with and into the Company, with the Company surviving the Merger as a subsidiary of Parent (the “Merger”).

3.          Part 1 of Schedule A hereto sets forth a list of each bareboat charter (each a “Covered Agreement”) to which the Company or one or more of its subsidiaries is a party where GLNG guarantees certain obligations of the Company or such subsidiaries (“Guarantees”), and Part 2 of Schedule A hereto describes certain credit support required in respect of obligations of companies in which the Company owns an interest (“Required Credit Support”).

4.        Schedule B hereto sets forth a form of management agreement that is intended to amend, restate and replace each of the Management Agreements to which the Tier 1 Service Provider and the Owners are a party, with such terms being further amended and superseded as further detailed and defined in Article II hereof.

5.          The Parties desire by their execution of this Agreement to evidence their understanding with respect to (i) certain obligations of Parent and GLNG with respect to the Guarantees and (ii) the management services to be provided to Parent and its subsidiaries by certain subsidiaries of GLNG pursuant to the Management Agreements.

In consideration of the premises and the covenants, conditions, and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree that the provisions of Article I and Article II and related Schedules shall be effective on and from the Effective Time (as defined in the Merger Agreement) (the “Effective Time”) as follows:

ARTICLE I

INDEMNIFICATION

Section 1.1.        Parent Payment Obligation Under Covered Agreements; Indemnification.  For each Covered Agreement on and from the Effective Time, (i) Parent will pay to GLNG a guarantee fee equal to $250,000 per annum, (pro-rated for the number of days in the year during which relevant such Guarantee is outstanding), payable semiannually in arrears, (ii) Parent will be primarily responsible to GLNG for the payment of any amounts payable pursuant to such Guarantees, as the case may be, as incurred, and (iii) Parent shall indemnify GLNG for any amounts GLNG pays under such Guarantees, as the case may be, and for any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs and expenses (including, without limitation, court costs and reasonable attorneys’ and experts’ fees, as incurred) of any and every kind or character arising out of or related to such Guarantees, as the case may be and in accordance with Section 1.2 and Section 1.3.

Section 1.2.        Notification of Parent Payment Obligation.  GLNG agrees that it will promptly and in any event within two days provide Parent (i) notice after it becomes aware of facts giving rise to a payment obligation under a Guarantee, specifying the amount to be paid thereunder, the date on which such payment obligations fall due (each a “Demand Date”) and specifying instructions for the payment of such funds in accordance with Section 1.3 (such notice the “Parent Payment Notice”), and (ii) copies of any notices, demands or other correspondence served on GLNG by the beneficiary under the Guarantee in relation to such Guarantee.

Section 1.3.         Notification of Claim for Indemnification.  In the event that Parent fails to make a payment to GLNG by the Demand Date specified in the relevant Parent Payment Notice: (i) GLNG shall make such payment and (ii) shall promptly provide Parent notice confirming that it has done so and requiring Parent to make payment of the amount for which GLNG is entitled to indemnification under Section 1.1 of this Agreement by a date falling no earlier than ten (10) days from the date on which Parent receives the Parent Payment Notice.

Section 1.4.         Guarantees.  GLNG agrees that on and from the Effective Time it will maintain all Guarantees required pursuant to, and in accordance with the terms of, the Covered Agreements to which they are in issue, (ii) comply with all covenants and terms to which GLNG is subject in the Guarantees, and the Covered Agreements in respect of which such Guarantees are issued, if any, and (iii) provide Parent with quarterly covenant compliance reports in respect of all applicable financial covenants, if any.

Section 1.5.         Notification of GLNG Payment Obligation.  In the event that GLNG  fails to comply with the requirements of Section 1.4 or Section 1.6, GLNG shall promptly notify Parent of such breach as soon as GLNG has become aware thereof, having made all due and careful enquiry.

Section 1.6.        Notification of Claim for GLNG Indemnification.  Parent shall promptly provide GLNG notice specifying the amounts for which Parent, the Company and/or its subsidiaries are entitled to indemnification under Section 1.4 and this Section 1.6 and GLNG shall indemnify Parent and the relevant subsidiaries for any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs and expenses (including, without limitation, court costs and reasonable attorneys’ and experts’ fees, as incurred) of any and every kind or character arising out of or related to GLNG’s failure to comply with GLNG’s obligations.

Section 1.7.         Subrogation.  With respect to any amount paid by Parent pursuant to Section 1.1(ii) and (iii) or Section 1.4, GLNG shall on and from the date of any such payment assign to Parent any rights of contribution or subrogation against the Company and, as applicable, its subsidiaries corresponding to such amount.

Section 1.8.        Cooperation.  On and from the Effective Time, each of GLNG and Parent shall use reasonable endeavors to have GLNG removed as guarantor or counter-indemnifier, as the case may be, under the Covered Agreements.

Section 1.9.          Required Credit Support.

(a)        GLNG shall, at its sole cost, maintain in full force and effect any letter(s) of credit, guarantee(s) or other credit support currently being maintained in respect of any Required Credit Support.

(b)        GLNG shall maintain in full force and effect the $5.75 million Irrevocable Standby Letter of Credit, Reference No. 39662244 (the “SSA L/C”), issued by Citibank, N.A., as issuing bank, for the benefit of Citibank N.A., in its capacity as Offshore Collateral Trust Agent, as Additional Equity Support in respect of the Additional Equity Commitment in accordance with the Amended and Restated Sponsor Support and Share Retention Agreement dated as of February 4, 2019 (the “SSA”), among CELSE – Centrais Elétricas de Sergipe S.A., as Borrower, CELSEPAR – Centrais Elétricas de Sergipe Participações S.A. as the Direct Shareholder, EBRASIL Energia Ltda., as the EBRASIL Shareholder, Golar Power Brasil Participações S.A., Golar Power Latam Participações e Comércio Ltda. and LNG Power Ltd., as the Golar Shareholders, Eletricidade do Brasil S.A. – EBRASIL and Golar Power Ltd., as the Sponsors, Golar LNG Ltd. and Stonepeak Infrastructure Fund II Cayman (G) Ltd., as the Golar Parents, Citibank, N.A., as the Intercreditor Agent, Citibank, N.A., as the Offshore Collateral Agent, and Banco Citibank S.A., as the Onshore Collateral Agent (as amended, modified, supplemented, restated and in effect from time to time), until the earlier of (x) May 1, 2021 and (y) the date on which Parent procures the replacement of the SSA L/C in compliance with the terms of the SSA.  Parent will be primarily responsible to GLNG for the payment of any amounts payable pursuant to the SSA L/C, as the case may be, as incurred, and Parent shall indemnify GLNG for any amounts GLNG pays under the SSA L/C, as the case may be, and for any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs and expenses (including, without limitation, court costs and reasonable attorneys’ and experts’ fees, as incurred) of any and every kind or character arising out of or related to the SSA L/C, as the case may be.

ARTICLE II

MANAGEMENT AGREEMENTS

Section 2.1.         Amendment and Restatement.  All management agreements and management services agreements between Owners and Tier 1 Service Provider shall be amended and restated on and from the Effective Time in the form appended at Schedule B (such amended and restated management agreements being the “Tier 1 Management Agreements”) provided that in the event of any conflict between any term of a Tier 1 Management Agreement and this Article II, this Article II shall prevail.

Section 2.2.        Manager Termination Right. Without prejudice to any express right of termination a Tier 1 Service Provider or Tier 2 Service Providers has to terminate any management agreement, including, without limitation, pursuant to Clause 22 of the relevant Tier 1 Management Agreement, to which it is a party (such agreements together the “Tier 1/Tier 2 Management Agreements”) in accordance with the terms of such management agreement, in exercising any express right to terminate for convenience under a management agreement, including, without limitation, pursuant to Clause 21 of the relevant Tier 1 Management Agreement, each Tier 1 Service Provider or Tier 2 Service Provider shall , except to the extent that (i) the vessel to which such Tier 1/Tier 2 Management Agreement relates continues to be the subject of a bareboat charter, a time charter party agreement, an FSRU lease agreement, a liquefaction tolling agreement or gas agreement (together the “Charter Contracts”) and (ii) where such management agreement termination would reasonably be expected to trigger a termination right relating to the change in the identity of the manager of the relevant vessel under its Charter Contract, be entitled to exercise such right to terminate any Tier 1/Tier 2 Management Agreement by giving sixty (60) days’ notice to the relevant Owner (such termination, a “Manager Termination Right for Convenience”).

Section 2.3.        Owner Termination Right.  Owner may terminate any Tier 1 Management Agreement for its convenience by giving sixty (60) days’ notice to the Tier 1 Service Provider.

Section 2.4.          Limitation on Liability.  Any provision of a Tier 1/Tier 2 Management Agreement that would, but for this Section 2.4, have the effect of capping or limiting the liability of the Tier 1 Service Provider or a Tier 2 Service Provider thereunder, as the case may be, shall not apply in the event that such Tier 1/Tier 2 Management Agreement is terminated by a Tier 1 Service Provider or Tier 2 Service Provider (i) pursuant to any Manager Termination Right for Convenience which does not comply with Section 2.2 of this Agreement or (ii) in a manner that is not expressly contemplated in such Tier 1/Tier 2 Management Agreement (as amended by Section 2.2 of this Agreement), where such management agreement termination triggers a termination right relating to the change in the identity of the manager of the relevant vessel under its Charter Contract).

Section 2.5.         Services Provision. Subject to the terms hereof and the relevant Tier 1/Tier 2 Management Agreements,  the Tier 1 Service Provider and the Tier 2 Service Providers will continue to provide such services as are set out in, and in accordance with, the relevant Tier 1/Tier 2 Management Agreements and any other management agreements to which the Tier 2 Service Providers are a party, and the consultancy services under the Tier 1 Management Agreement shall without limitation include such advisory or other additional services as may be reasonably requested by the Partnership to enable the Owners to comply with each Charter Contract and any related financing arrangement covenant relating to management service provision, change of control and ownership, in each case as relate to the transaction contemplated by the Merger Agreement and this Agreement.

Section 2.6.          Cool Pool.

(a)        Each of Parent, GLNG and The Cool Pool Limited (“Cool Pool”) acknowledges and agrees that the Golar Celsius and the Golar Penguin (the “Vessels”) are currently trading in the LNG carrier pool (the “LNG Pool”) managed by Cool Pool as one of the vessels managed by GLNG and its Affiliates, and that both Vessels are currently  subject to time charter parties entered into between (i) in the case of the Golar Penguin, Golar M2023 and RWE Supply & Trading GmbH (the “Penguin Charter”); and (ii) in the case of the Golar Celsius, Golar M2026 and Cool Pool under a head charter and between Cool Pool and Uniper Global Commodities SE under a sub charter (the “Celsius Charter”, and together with the Penguin Charter, the “Pool Charters”).

(b)         Each of GLNG and Cool Pool acknowledges and agrees that Parent may at any time after the date of this Agreement serve a notice on Cool Pool requesting the withdrawal of any of the Vessels from the LNG Pool. With effect from the receipt of such notice, each of GLNG and Cool Pool agrees that it shall (i) not enter into any further negotiation, arrangement, time charter or other agreement with any party with respect to the Vessels; and (ii) take such further actions reasonably requested by Parent in order to fully and unconditionally release the Vessels from any obligations under the applicable Pool Charter and make the Vessels fully available to Parent and its subsidiaries for charter to a third party promptly following such release.

ARTICLE III

MISCELLANEOUS

Section 3.1.        Choice of Law; Submission to Jurisdiction.  This Agreement shall be subject to and governed by the laws of the State of New York.

Section 3.2.         Notice.  All notices, requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing the same in the mail, addressed to the Person to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by private-courier, prepaid, by telecopier to such party or by e-mail to such party.  Notice given by personal delivery or mail shall be effective upon actual receipt.  Couriered notices shall be deemed delivered on the date the courier represents that delivery will occur.  Notice given by e-mail or telecopier shall be effective upon actual receipt if received during the recipient’s normal business hours, or at the beginning of the recipient’s next business day after receipt if not received during the recipient’s normal business hours.  All notices to be sent to a party pursuant to this Agreement shall be sent to or made at the address set forth below such party’s signature to this Agreement, or at such other address as such party may stipulate to the other parties in the manner provided in this Section 3.2.

Section 3.3.         Entire Agreement.  This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding all prior contracts or agreements, whether oral or written, relating to the matters contained herein.

Section 3.4.         Termination.  This Agreement shall terminate at the latest to occur of (a) no Guarantee remaining outstanding, (b) each of Parent and GLNG has paid all amounts due pursuant to Article I, (c) the termination of all Covered Agreements, (d) the termination of all management agreements and management services agreements to which the Tier 1 Service Provider and Tier 2 Service Providers are a party and (e) the termination or expiration of each agreement under which any Required Credit Support is required.

Section 3.5.        Amendment or Modification.  This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto.

Section 3.6.          Assignment.  No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto.

Section 3.7.         Counterparts.  This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document.  All counterparts shall be construed together and shall constitute one and the same instrument.

Section 3.8.        Severability.  If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

Section 3.9.         Gender, Parts, Articles and Sections.  Whenever the context requires, the gender of all words used in this Agreement shall include the masculine, feminine and neuter, and the number of all words shall include the singular and plural.  All references to Article numbers and Section numbers refer to Articles and Sections of this Agreement.

Section 3.10.      Further Assurances.  In connection with this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement.

[Signature page follows.]

IN WITNESS WHEREOF, the Parties have executed this Agreement on, and effective as of, the date first written above.

GOLAR LNG LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
Address for Notice for GLNG, Cool Pool, the Tier 1 Service Provider and the Tier 2 Service Providers:
Golar Management Ltd
6th Floor, The Zig Zag
70 Victoria Street
London SW1E 6SQ
United Kingdom
Email:	karl.staubo@golar.com
	GMLLegal@golar.com
Attention: Karl Fredrik Staubo

NEW FORTRESS ENERGY INC.
By:	/s/ Christopher Guinta
	Name:	Christopher Guinta
	Title:	Director
Address for Notice for the Parent and the Owners:
New Fortress Energy Inc.
111 W. 19th Street, 8th Floor
New York, New York 10011
Attn:	General Counsel
Email:	legal@newfortressenergy.com
Phone:	516-268-7400

THE COOL POOL LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
GOLAR HULL M2026 CORP.
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
GOLAR HULL M2023 CORP.
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
GOLAR NANOOK UK LIMITED
By:	/s/ Rodrigo Fortes
	Name:	Rodrigo Fortes
	Title:	Director
GOLAR FSRU8 CORPORATION
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
GOLAR MANAGEMENT (BERMUDA) LIMITED
By:	By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
GOLAR MANAGEMENT LTD
By:	/s/ Malcom Bulbeck
	Name:	Malcom Bulbeck
	Title:	Director

GOLAR MANAGEMENT NORWAY AS
By:	/s/ Erling David-Andersen
	Name:	Erling David-Andersen
	Title:	Director
GOLAR MANAGEMENT D.O.O.
By:	/s/ Lasse Røed
	Name:	Lasse Røed
	Title:	Director
GOLAR MANAGEMENT MALAYSIA SDN BHD
By:	/s/ Jamal Ishak Aziz Ahmad
	Name:	Jamal Ishak Aziz Ahmad
	Title:	General Manager

Schedule A

Part 1

Covered Agreements

Charters

1. Bareboat Charter dated March 3, 2020 between Noble Celsius Shipping Limited and Golar Hull M2026 Corporation.

2. Bareboat Charter dated December 17, 2019 between Oriental Fleet LNG 02 Limited and Golar Hull M2023 Corporation.

3. Bareboat Charter for FSRU “Golar Nanook” dated 25 September 2018 between Compass Shipping 23 Corporation Limited and Golar FSRU8 Corporation.

Part 2

Required Credit Support

1. The Indemnitor Letter of Credit issued by GLNG in accordance with section 2 of the indemnity agreement entered into between GLNG, the Company and Stonepeak Infrastructure Fund II Cayman (G) Ltd on 15 April 2021.

Schedule B1

BIMCO Shipman Agreement to be inserted

Schedule B2

Bermuda Services Agreement to be inserted

Schedule C

Management Agreements

Tier 1 Management Agreements

Asset	Golar Counterparty / Owner	Tier 1 Service Provider
Nanook	Golar FSRU8 Corporation (to be replaced by Golar Nanook UK Limited from the Effective Time in the discretion of the Parent)	GML
Celsius	Golar Hull M2026 Corp.	GML
Penguin	Golar Hull M2023 Corp.	GML
Corporate	Hygo Energy Transition Ltd	Golar Management Bermuda

Tier 2 Management Agreements

Counterparty	Service Provider
GML	Golar Management Norway AS
GML	Golar Management Malaysia SDN BHD
GML	Golar Management D.O.O.

Schedule D

Parties

Golar LNG Limited, a Bermuda exempted company (“GLNG”), The Cool Pool Limited, a Marshall Islands company (“Cool Pool”), Golar Hull M2026 Corp., a Marshall Islands corporation (“Golar M2026”), Golar Hull M2023 Corp., a Marshall Islands corporation (“Golar M2023”), Golar FSRU8 Corporation, a Marshall Islands corporation (“Golar FSRU8”), Golar Nanook UK Limited, an England & Wales company (“Golar Nanook”, and, together with Golar FSRU8, Golar M2026 and M2023, the “Owners”), Golar Management Ltd (“GML”), an England and Wales company, the “Tier 1 Service Provider”), Golar Management Norway AS, a Norway company (“Golar Norway”), Golar Management Malaysia SDN BHD, a Malaysia company (“Golar Malaysia”), Golar Management D.O.O., a Croatia company (“Golar Croatia”), Golar Management (Bermuda) Limited, a Bermuda exempted company (“Golar Management Bermuda” and together with GML, Golar Norway, Golar Malaysia, and Golar Croatia, the “Tier 2 Service Providers”) and New Fortress Energy Inc., a Delaware corporation (“Parent” and together with Cool Pool, GLNG, the Owners, the Tier 1 Service Provider and the Tier 2 Service Providers, the “Parties”).

EX-10.31

Exhibit 10.31

EXECUTION VERSION

INDEMNITY AGREEMENT

This Indemnity Agreement (this “Agreement”) is made by GOLAR LNG LIMITED (“GLNG”), a Bermuda exempted company, and STONEPEAK INFRASTRUCTURE FUND II CAYMAN (G) LTD. (“Stonepeak”) (each an “Indemnitor” and together, the “Indemnitors”), in favor of HYGO ENERGY TRANSITION LTD. (f/k/a Golar Power Ltd.) (“Hygo”), a Bermuda exempted company.

WHEREAS, immediately prior to the entry into this Agreement, GLNG and Stonepeak were the sole shareholders of Hygo, whose rights and obligations with respect to Hygo were governed by that certain Investment and Shareholders Agreement, dated July 5, 2016, by and among, GLNG, Stonepeak and Hygo (the “Shareholders Agreement”);

WHEREAS, GLNG and Stonepeak, immediately prior to the date hereof, are parties to that certain Amended and Restated Sponsor Support and Share Retention Agreement, dated as of February 4, 2019 (as amended, modified, supplemented, restated and in effect from time to time, the “A&R Sponsor Support and Share Retention Agreement”), by and among CELSE – Centrais Elétricas de Sergipe S.A., as the Borrower, CELSEPAR – Centrais Elétricas de Sergipe Participações S.A., as the Direct Shareholder (“CELSEPAR”), EBRASIL Energia Ltda., as the EBRASIL Shareholder, Golar Power Brasil Participações S.A., as a Golar Shareholder, LNG Power Ltd., as a Golar Shareholder, Golar Power Latam Participações e Comércio Ltda., as a Golar Shareholder, Eletricidade do Brasil S.A. – EBRASIL (“EBRASIL”), as a Sponsor, Hygo, as a Sponsor, GLNG, as a Golar Parent, Stonepeak, as a Golar Parent, Citibank, N.A., as the Intercreditor Agent and Offshore Collateral Agent, and Banco Citibank, S.A., as the Onshore Collateral Agent;

WHEREAS, pursuant to that certain Agreement and Plan of Merger (the “Merger Agreement”), dated as of January 13, 2021, by and among Hygo, GLNG, Stonepeak, New Fortress Energy Inc. (“NFE”) and Lobos Acquisition Ltd. (the “Merger Sub”), upon the terms and subject to the conditions thereof, Merger Sub will merge with and into Hygo (the “Merger”), with Hygo continuing as the surviving company in the Merger and becoming a wholly-owned subsidiary of NFE;

WHEREAS, pursuant to that certain Side Letter, dated as of March 30, 2021, from CELSEPAR (and agreed and accepted by Hygo and EBRASIL, as Sponsors) to Citibank, N.A., as Intercreditor Agent and as Offshore Collateral Agent, Inter-American Investment Corporation, as the IDB Invest Senior Lender Representative, the IDB Senior Lender Representative and the China Fund Senior Lender Representative, International Finance Corporation, as the IFC Senior Lender Representative, Credit Suisse AG, as Policyholder Agent, and Pentágono S.A. Distribuidora de Títulos e Valores Mobiliários, as Fiduciary Agent (the “Sponsor Support Side Letter”), (i) CELSEPAR agreed to procure the delivery by Hygo and EBRASIL of, and Hygo and EBRASIL have executed, that certain Guaranty, dated as of March 30, 2021, in favor of the Offshore Collateral Agent (the “Guaranty”), pursuant to which Hygo and EBRASIL guarantee on a several (but not joint) basis certain Guaranteed Obligations (as defined in the Guaranty) of CELESPAR under the Sponsor Support Side Letter and (ii) CELSEPAR has agreed, on or prior to April 15, 2021, to deliver to the Intercreditor Agent one or more Acceptable Letters of Credit in favor of the Offshore Collateral Agent in an aggregate stated amount of US$6,000,000, in furtherance of CELESPAR’s obligations under the Sponsor Support Side Letter; and

WHEREAS, on and subject to the terms set forth herein, GLNG and Stonepeak have each agreed, on a several (but not joint) basis (i) to indemnify Hygo in respect of its obligations under the Guaranty and (ii) to procure the delivery to the Intercreditor Agent of an Acceptable Letter of Credit in favor of the Offshore Collateral Agent with a face value of US$1,500,000 for each such Acceptable Letter of Credit.

NOW, THEREFORE, in consideration of good and valuable consideration, the adequacy, receipt and sufficiency of which are hereby acknowledged, Indemnitor hereby agrees as follows:

1. Indemnification. Each Indemnitor hereby agrees to indemnify on a several (but not joint) basis Hygo for an amount equal to fifty percent (50%) (“Pro Rata Share Amount”) of any and all amounts paid by Hygo to the Offshore Collateral Agent in respect of the Guaranteed Obligations under the Guaranty (“Indemnified Obligations”); provided, however, in no event shall the Indemnified Obligations exceed (i) an amount in the aggregate (the “Aggregate Cap”) equal to the lower of (x) US$6,000,000 and (y) the amount actually paid by Hygo to the Offshore Collateral Agent in respect of the Guaranteed Obligations under the Guaranty or (ii) with respect to each individual Indemnitor, an amount (the “Individual Cap”) equal to the lower of (x) $3,000,000 and (ii) fifty percent (50%) of the amount actually paid by Hygo to the Offshore Collateral Agent in respect of the Guaranteed Obligations under the Guaranty; and further provided that, notwithstanding anything else in this Agreement, in no event will either Indemnitor have aggregate liability or other obligations under this Agreement or otherwise in connection with the Indemnified Obligations in excess of an amount (together with the Aggregate Cap and Individual Cap, the “Cap”) equal to (x) US$3,000,000, less (y) the face value of any Indemnitor Letter of Credit procured and delivered by such Indemnitor in accordance with Section 2 below (in the case of this clause (y), so long as such Indemnitor Letter of Credit remains in effect).  Each of the parties hereby expressly acknowledges and agrees that in no event may this Agreement be enforced without giving effect to the Cap, and that this Agreement may be enforced by Hygo for the payment of money only.

2. Letter of Credit. Each Indemnitor hereby agrees, (i) on or before April 15, 2021, to individually procure the delivery to the Intercreditor Agent of an Acceptable Letter of Credit in favor of the Offshore Collateral Agent with a face value of US$1,500,000 (each an “Indemnitor Letter of Credit”) and (ii) to maintain such Indemnitor Letter of Credit in full force and effect as required under the Sponsor Support Side Letter.

3. Termination.

This Agreement shall be and continue to be in full force and effect from the Effective Date until the earliest of: (a) the termination of the Sponsor Support Side Letter; (b) the Completion Support Release Date (as defined in the Sponsor Support Side Letter); (c) the full and final discharge and satisfaction of the Indemnified Obligations; or (d) the amendment of the Guaranty or the Sponsor Support Side Letter in a manner materially adverse to the Indemnitors without the express written consent of the Indemnitors; provided, however, any such termination shall not release the Indemnitors from their respective obligations with respect to any Indemnified Obligations arising prior to the effectiveness of, or in conjunction with (and including, without limitation, debt amounts outstanding as of the date of) such termination (even if the amount of any such Indemnified Obligation is not then fully determined).

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Upon the occurrence of any such event listed in Section 3 above, notwithstanding anything herein to the contrary, this Agreement and each Indemnitor’s liability hereunder shall immediately and automatically terminate and expire (other than any liability expressly contemplated as surviving pursuant to the provisions in this Section 3).

Notwithstanding anything to the contrary, in the event that Hygo or any of its Affiliates, or any person or entity claiming by, through or on behalf or in the name or for the benefit of Hygo or any of its Affiliates, asserting a claim in writing, or otherwise in any litigation or other adversarial proceeding (whether under any theory at law or equity or otherwise) (i) that the provisions of Section 1 hereof limiting an Indemnitor’s liability to the Cap and limiting Hygo’s enforcement hereof to the payment of money only, or the provisions of this Section 3 or Sections 7 through 11 are illegal, invalid or unenforceable in whole or in part, or (ii) any theory of liability against any Indemnitor or any Non-Recourse Party (as defined below) with respect to the transactions contemplated by this Agreement or the Indemnified Obligations, other than claims solely by Hygo against the Indemnitors under (and solely in accordance with) this Agreement, then in any such case of the foregoing clauses (i) or (ii), (x) the obligations of the Indemnitors under this Agreement shall terminate ab initio and shall thereupon be null and void, (y) if any Indemnitor has previously made any payments under this Agreement, Hygo shall immediately upon demand refund such payments and the applicable Indemnitor(s) shall be entitled to recover such payments from Hygo, and (z) neither the Indemnitors nor any Non-Recourse Parties shall have any liability to Hygo or any of its Affiliates under this Agreement, or in respect of the Indemnified Obligations or any of the transactions contemplated hereby.

Further notwithstanding anything to the contrary, including without limitation anything that may be expressed or implied in this Agreement or any document or instrument delivered contemporaneously herewith, and notwithstanding the fact that an Indemnitor may be a limited partnership, by its acceptance of the benefits of this Agreement, each of the parties acknowledges and agrees that (i) no person or entity other than the Indemnitors and Hygo has any liability or other obligations hereunder and (ii) there is no remedy, recourse or right of recovery against, and no personal liability shall attach to, any former, current or future director, officer, employee, agent, attorney, direct or indirect equityholder, controlling person, general or limited partner, manager, member, stockholder, co-investor, Affiliate or assignee of any Indemnitor or its Affiliates, or any former, current or future director, officer, employee, agent, attorney, direct or indirect equityholder, controlling person, general or limited partner, manager, member, stockholder, co-investor, Affiliate or assignee of any of the foregoing (each of the foregoing, including, without limitation, the Indemnitors, a “Non-Recourse Party”), through an Indemnitor or otherwise, whether by or through attempted piercing of the corporate (or limited liability company or partnership) veil, by the enforcement of any assessment or by any legal or equitable proceeding, by virtue of any applicable law or otherwise, in each case of the foregoing, except for (claims solely by Hygo against the Indemnitors under (and solely in accordance with) this Agreement.

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Each party hereby covenants and agrees that except for claims against the Indemnitors and Hygo under (and solely in accordance with) this Agreement, it shall not institute, and shall cause each of its Affiliates and each of the respective agents and representatives of the foregoing not to institute, directly or indirectly, any litigation or other adversarial proceeding or to bring any other claim relating to, arising under, or in connection with, this Agreement, the Indemnified Obligations or any of the other transactions contemplated hereby, against any Non-Recourse Party.

4. Notices.  All notices, requests and other communications hereunder shall be in writing and shall be (a) delivered personally, (b) sent by nationally recognized overnight courier or (c) by delivery of a PDF copy by electronic mail, read receipt requested, in each case addressed to the appropriate party at the address for such party shown below or at such other address as such party shall have theretofore designated by written notice delivered to the party giving such notice:

If to Hygo, to:	Hygo Energy Transition Ltd. c/o New Fortress Energy Inc. 111 W. 19th Street, 8th Floor Attention: General Counsel E-mail: legal@newfortressenergy.com
If to GLNG, to:	Golar LNG Limited 2nd Floor, S.E. Pearman Building, 9 Par-la-Ville Road Hamilton HM 11, Bermuda Attention: Karl Staubo Email: karl.staubo@golar.com; GMLLegal@golar.com
If to Stonepeak, to:	Stonepeak Infrastructure Fund II Cayman (G) Ltd. 55 Hudson Yards, 550 W 34th Street, 48th Floor New York, New York 10001 Attention: Adrienne Saunders; James Wyper Email: saunders@stonepeakpartners.com; wyper@stonepeakpartners.com

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier during normal business hours, or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in the mail, or upon written confirmation of receipt if given by electronic mail, as the case may be (provided, that a “read receipt” shall constitute such written confirmation). The parties may change the address, telephone numbers, and email addresses to which such communications are to be addressed by giving written notice to the other Parties in the manner provided in this Section 4.

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5. Demand and Payment.  Any demand by Hygo for payment from the Indemnitors hereunder shall: (a) be in writing; (b) reference this Agreement; (c) specify the amount of Indemnified Obligations Hygo claims it is owed and the amounts paid by Hygo to the Offshore Collateral Agent under the Guaranty; (d) specify the Pro Rata Share Amount owed by each Indemnitor with respect to the Indemnified Obligations, (e) include evidence of the payment made by Hygo to the Offshore Collateral Agent under the Guaranty and a statement describing in reasonable detail and with reasonable specificity the circumstances surrounding Hygo’s incurrence of the liabilities that give rise to the Indemnified Obligations; (f) be signed by a duly authorized officer of Hygo; and (g) be delivered to each Indemnitor pursuant to Section 4 hereof. So long as such demand complies with the foregoing sentence and payment is otherwise due from an Indemnitor in accordance with this Agreement, such Indemnitor shall pay, or cause to be paid, the amount so due in respect of the Indemnified Obligations within ten (10) Business Days of receipt of such demand (for the avoidance of doubt, subject to the Cap). Hygo shall provide any further documentary evidence reasonably requested by each Indemnitor relating to such demand and the Guaranteed Obligations that give rise to the applicable Indemnified Obligations. All payments under this Agreement shall be made without deduction or withholding for or on account of any present or future taxes; provided, however, that if any applicable law requires the deduction or withholding of any tax from any such payment, then each Indemnitor shall be entitled to make such deduction or withholding and shall timely pay the full amount deducted or withheld to the relevant governmental authority in accordance with applicable law, and the sum payable by each Indemnitor shall be increased as necessary so that after such deduction or withholding has been made, Hygo receives an amount equal to the sum it would have received had no such deduction or withholding been made.

6. Letter of Credit Payments. GLNG and Stonepeak each acknowledge and agree that in the event that the Offshore Collateral Agent makes a demand for payment under an Indemnitor Letter of Credit, then such Indemnitor party (“Paying LC Party”) shall promptly provide written notice to the other Indemnitor party (“Non-Paying LC Party”) of such payment amount and if the Offshore Collateral Agent did not make a demand under the Non-Paying LC Party’s Indemnitor Letter of Credit, or made a demand for less than the amount demanded under the Paying LC Party’s Indemnitor Letter of Credit, the Non-Paying LC Party agrees to reimburse the Paying LC Party for an amount equal to the difference between (a) fifty percent of the aggregate amount demanded under each Indemnitor Letter of Credit and (b) the amount demanded by the Offshore Collateral Agent under the Non-Paying LC Party’s Indemnitor Letter of Credit, within fifteen (15) Business Days of receipt of such notice.

7. No Waiver; Remedies.  Except as to applicable statutes of limitation, no failure on the part of any party to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right.  The remedies herein provided are cumulative and not exclusive to any remedies provided by law.

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8. Assignment; Successors and Assigns.  No party hereto may assign or delegate any of its respective rights or obligations hereunder without the prior written consent of the other parties; provided, however, that each Indemnitor may, without the prior written consent of the other parties, assign its rights and obligations under this Agreement to (i) any Affiliate of such Indemnitor that has assets and liquidity in an amount equal to or greater than the assets and liquidity of such Indemnitor as of the date of the proposed assignment or (ii) any assignee that acquires all or substantially all of the assets of such Indemnitor.  Any assignment that does not comply with the terms of this Section 8 shall be deemed null and void and of no force or effect.  This Agreement shall be binding upon and inure to the benefit of each party hereto and their respective successors and permitted assigns.

9. Amendments, etc.  No amendment or other modification of the terms of this Agreement shall be effective unless in writing and signed by each Indemnitor and Hygo and stating that it is expressly intended to give effect to the applicable amendment or modification hereto.  Neither any waiver of any provision of this Agreement nor consent to any departure by either party therefrom shall be effective in any event unless such waiver shall refer to this Agreement, be in writing and be signed by such party.  Any such waiver shall be effective only in the specific instance and for the specific purpose for which it was given.

10. Headings and Definitions.  The headings and captions used in this Agreement have been inserted for convenience only and shall be given no substantive meaning or significance whatsoever in construing the terms and provisions hereof.  Any capitalized term utilized but not defined herein shall have the meaning given to such term in the Guaranty (including by incorporation), in the A&R Sponsor Support and Share Retention Agreement or in Annex I to the Common Terms Agreement, as applicable.

11. Governing Law; Jurisdiction; Jury Waiver.

(a) This Agreement shall be governed by, construed and enforced in accordance with the laws of the State of New York, without regard to choice of law principles that would require the application of the laws of any other jurisdiction.

(b) Each of the parties hereto hereby (i) consents to submit itself to the personal jurisdiction and venue of the courts of the State of New York sitting in New York County or, if such courts shall not have jurisdiction, the United States District Court of the Southern District of New York, and any appellate court thereof, with respect to any suit relating to or arising out of this Agreement or any of the transactions contemplated hereby, (ii) agrees that it will, to the fullest extent it may effectively do so, not attempt to defeat or deny such personal jurisdiction or venue by motion or otherwise, (iii) agrees that it will not bring any action or proceeding with respect to this Agreement in any court other than a court of the State of New York sitting in New York County or, if applicable pursuant to clause (i) above, the United States District Court of the Southern District of New York, and any appellate court thereof, (iv) irrevocably agrees that any action or proceeding with respect to, arising directly or indirectly in connection with, out of, related to, or from this Agreement or any transactions contemplated hereby (whether at law, in equity, in contract, in tort or otherwise) shall be heard and determined exclusively in a court of the State of New York sitting in New York County or, if applicable pursuant to clause (i) above, the United States District Court of the Southern District of New York, and any appellate court thereof, (v) agrees to service of process in any such action in any manner prescribed by the laws of the State of New York, and (vi) agrees that service of process upon such party hereto in any action or proceeding shall be effective if notice is given in accordance with Section 4.  The parties hereto further agree, to the fullest extent permitted by law, that a final and non-appealable judgment against any of them in any action or proceeding contemplated above shall be conclusive and may be enforced in any other jurisdiction within or outside the United States by suit on the judgment, a certified copy of which shall be conclusive evidence of the fact and amount of such judgment, a certified or exemplified copy of which shall be conclusive evidence of the fact and amount of such judgment.

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(c) To the extent that any party hereto has or hereafter may acquire any immunity from jurisdiction of any court or from any legal process (whether through service of notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, each such party hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement and (ii) submits to the personal jurisdiction of any court described in Section 11(b).

(d) Each party hereto hereby irrevocably and unconditionally waives, to the fullest extent it may legally and effectively do so, any objection which it may now or hereafter have to the laying of venue of any suit, action or proceeding arising out of or relating to this Agreement or the transactions contemplated hereby in any court referred to in Section 11(b). Each of the parties hereto hereby irrevocably waives, to the fullest extent permitted by applicable law, the defense of an inconvenient forum to the maintenance of such action or proceeding in any such court.

(e) EACH PARTY TO THIS AGREEMENT HEREBY KNOWINGLY AND VOLUNTARILY WAIVES ITS RIGHTS TO TRIAL BY JURY IN ANY PROCEEDING INVOLVING OR IN ANY WAY RELATING TO ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY TRANSACTION CONTEMPLATED HEREBY.

12. Entire Agreement. This Agreement contains the entire agreement between the parties hereto with respect to the subject matter hereof and supersedes any prior understandings, agreements or representations by or between the parties hereto, written or oral, that may have related to the subject matter hereof in any way.

13. Severability.  Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is held to be prohibited by or invalid under applicable law, such provision shall be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provisions or the remaining provisions of this Agreement.

14. Counterparts.  This Agreement may be executed in multiple counterparts (including by PDF or electronic means), each of which shall be deemed an original but all of which taken together shall constitute one and the same instrument.

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15. Special Damages. In no event shall an Indemnitor be liable for any special, exemplary, punitive or consequential or indirect damages resulting from or arising out of this Agreement, except to the extent such damages are Guaranteed Obligations for which Hygo has made payment under the Guaranty.

[Remainder of page intentionally left blank.]

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IN WITNESS WHEREOF, each Indemnitor has caused this Agreement to be duly executed and delivered by its duly authorized officers effective as of this 15th day of April, 2021 (the “Effective Date”).

STONEPEAK INFRASTRUCTURE FUND II CAYMAN (G) LTD.
By:	/s/ Luke Taylor
	Name:	Luke Taylor
	Title:	Senior Managing Director

[Signature Page to Indemnity Agreement]

GOLAR LNG LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

[Signature Page to Indemnity Agreement]

Acknowledged and agreed to this 15th day of April, 2021.

HYGO ENERGY TRANSITION LTD.
By:	/s/ Eduardo Maranhao
	Name:	Eduardo Maranhao
	Title:	CFO

[Signature Page to Indemnity Agreement]

EX-10.32

Exhibit 10.32

Execution Version

OMNIBUS AGREEMENT

THIS OMNIBUS AGREEMENT (this “Agreement”) is entered into as of April 15, 2021 by and between the Parties (as set out in Schedule D).

R E C I T A L S:

1. On January 13, 2021, Golar LNG Partners LP, a Marshall Islands limited partnership (the “Partnership”), entered into an agreement and plan of merger (the “Merger Agreement”) with Golar GP LLC, a Marshall Islands limited liability company and the general partner of the Partnership (the “General Partner”), New Fortress Energy Inc., a Delaware corporation (“Parent”),  Lobos Acquisition LLC, a Marshall Islands limited partnership and an indirect subsidiary of Parent (“Merger Sub”), and NFE International Holdings Ltd, a private limited company incorporated under the laws of England and Wales, United Kingdom and an indirect subsidiary of Parent (“GP Buyer”).

2.  Pursuant to the Merger Agreement, at the Effective Time (as such term is defined in the Merger Agreement), Merger Sub merged with and into the Partnership, with the Partnership surviving the Merger as a subsidiary of Parent (the “Merger”).

3.  Concurrently with the consummation of the Merger, GP Buyer purchased from GP Parent, and GP Parent transferred to GP Buyer, all of the outstanding membership interests of the General Partner (the “GP Transfer”), pursuant to a Transfer Agreement dated, January 13, 2021 (the “GP Transfer Agreement”).

4.  Schedule A hereto sets forth a list of each time charter party, FSRU lease agreement and performance guarantee (each a “Covered Agreement”) (i) to which the Partnership or one or more of its subsidiaries is a party or (ii) in respect of which the payment obligations of the issuing bank are subject to a counter-indemnification obligation and where one of the Charter Guarantors, in the case of clause (i), guarantees certain obligations of the Partnership or such subsidiaries (“GP Parent Guarantees”) and in the case of clause (ii), provides such counter-indemnity (“GP LC Counter-indemnities”).

5. Schedule B hereto sets forth a form of management agreement that is intended to amend, restate and replace each of the Management Agreements to which the Tier 1 Service Provider and the Owners are a party, with such terms being further amended and superseded as further detailed and defined in Article II hereof.

6. Golar Eskimo (as defined in Schedule D), which will be indirectly owned by Parent following the consummation of the Merger, is party to a Bareboat Charter, a Memorandum of Agreement and a Common Terms Agreement, each dated 4 November 2015 (collectively, the “Eskimo Bareboat Charter”), by and between Golar Eskimo and Sea 23 Leasing Co. Limited, a subsidiary of China Merchants Bank Limited, providing for the sale and leaseback of the Golar Eskimo.

7.  Golar LNG NB13 Corporation, a Marshall Islands corporation (“Golar NB13”), which will continue to be indirectly owned by GP Parent following the consummation of the Merger, is party to a Bareboat Charter, a Memorandum of Agreement and a Common Terms Agreement, each dated 19 November 2015 (collectively, the “Tundra Bareboat Charter”), by and between Golar NB 13 and Sea 24 Leasing Co. Limited, a subsidiary of China Merchants Bank Limited, providing for the sale and leaseback of the Golar Tundra.

8. Golar Hilli Corporation, a Marshall Islands corporation (“Golar Hilli”), in which each of Parent and GP Parent will own an indirect interest following the consummation of the Merger, is party to a Bareboat Charter, a Memorandum of Agreement and a Common Terms Agreement, each dated 9 September 2015 (collectively, the “Hilli Bareboat Charter”), by and among Golar Hilli, Fortune Lianjiang Shipping S.A., and GP Parent, as guarantor, providing for the sale and leaseback of the Hilli Episeyo.

9. The liquefied natural gas carrier named “METHANE PRINCESS” registered under Marshall Islands flag with IMO number 9253715 (the “Methane Princess”) is the subject of a sub-lease agreement dated 27 August 2003 between Golar LNG 2215 Corporation (“2215 Lessee”) as lessee and Golar 2215 (as defined in Schedule D) as sub-lessee. The Methane Princess is the subject of a Time Charter Party (as novated and restated), dated August 27, 2003, between Methane Services Limited and Golar 2215 (the “MP Time Charter”). 2215 Lessee and Golar 2215 will be indirectly owned by Parent following the consummation of the Merger.

10.GP Parent and Parent are parties to a letter agreement dated April 1, 2021 regarding the prepayment and repayment of certain funds in connection with the consummation of the Merger (the “Closing Payment Funding Letter”).

11.The Parties desire by their execution of this Agreement to evidence their understanding with respect to (i) certain obligations of Parent and Charter Guarantors with respect to the GP Parent Guarantees and LC Counter-indemnities, (ii) the management services to be provided to Parent and its subsidiaries by certain subsidiaries of GP Parent pursuant to the Management Agreements, (iii) mutual indemnification obligations of GP Parent in favor of Parent and of Parent in favor of GP Parent in respect of cross-default provisions in the Eskimo Bareboat Charter and Tundra Bareboat Charter, (iv) information rights in connection with the Hilli Bareboat Charter, and (v) certain indemnification obligations of GP Parent with respect to the Methane Princess.

In consideration of the premises and the covenants, conditions, and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree that the provisions of Article I and Article II and related Schedules shall be effective on and from the Effective Time (as defined in the Merger Agreement) (the “Effective Time”) as follows:

ARTICLE I

INDEMNIFICATION AND OTHER UNDERTAKINGS

Section 1.1.         Parent Payment Obligation Under Covered Agreements; Indemnification.  For each Covered Agreement on and from the Effective Time, (i) Parent will pay to relevant Charter Guarantor a guarantee fee of $250,000 per annum (pro-rated for the number of days in the year during which relevant such GP Parent Guarantee and/or GP LC Counter-indemnity is outstanding), payable semiannually in arrears, (ii) Parent will be primarily responsible to Charter Guarantors for the payment of any amounts payable pursuant to such GP Parent Guarantees and/or GP LC Counter-indemnities, as the case may be, as incurred, and (iii) Parent shall indemnify Charter Guarantors for any amounts Charter Guarantor pays under such GP Parent Guarantees and GP LC Counter-indemnities, as the case may be, and for any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs and expenses (including, without limitation, court costs and reasonable attorneys’ and experts’ fees, as incurred) of any and every kind or character arising out of or related to such GP Parent Guarantees and GP LC Counter-indemnities, as the case may be and in accordance with Section 1.2 and Section 1.3.

Section 1.2.        Notification of Parent Payment Obligation.  Each Charter Guarantor agrees that it will promptly and in any event within two days provide Parent (i) notice after it becomes aware of facts giving rise to a payment obligation under a GP Parent Guarantee or GP LC Counter-indemnity, specifying the amount to be paid thereunder, the date on which such payment obligations fall due (each a “Demand Date”) and specifying instructions for the payment of such funds in accordance with Section 1.3 (such notice the “Parent Payment Notice”), and (ii) copies of any notices, demands or other correspondence served on such Charter Guarantor by the beneficiary under the GP Parent Guarantee or issuing bank under the GP LC Counter-indemnity, as the case may be, in relation to such GP Parent Guarantee or GP LC Counter-indemnity.

Section 1.3.         Notification of Claim for Indemnification.  In the event that Parent fails to make a payment to the relevant Charter Guarantor by the Demand Date specified in the relevant Parent Payment Notice: (i) such Charter Guarantor shall make such payment and (ii) shall promptly provide Parent notice confirming that it has done so and requiring Parent to make payment of the amount for which such Charter Guarantor is entitled to indemnification under Section 1.1 of this Agreement by a date falling no earlier than ten (10) days from the date on which Parent receives the Parent Payment Notice.

Section 1.4.         GP Parent Guarantees and GP LC Counter-indemnities.  Each Charter Guarantor agrees that on and from the Effective Time it will (i) maintain all GP Parent Guarantees and renew and/or replace all GP LC Counter-indemnities required pursuant to, and in accordance with the terms of, the Covered Documents to which they are in issue, (ii) comply with all covenants and terms to which such Charter Guarantor is subject in the GP Parent Guarantees and GP LC Counter-indemnities, and the Covered Documents in respect of which such GP Parent Guarantees and GP LC Counter-indemnities are issued, if any, and (iii) provide Parent with quarterly covenant  compliance reports in respect of all applicable financial covenants, if any.

Section 1.5.         Notification of Charter Guarantor Payment Obligation.  In the event that a Charter Guarantor  fails to comply with the requirements of Section 1.4 or Section 1.6, such Charter Guarantor shall promptly notify Parent of such breach as soon as such Charter Guarantor has become aware thereof, having made all due and careful enquiry.

Section 1.6.         Notification of Claim for Charter Guarantor Indemnification.  Parent shall promptly provide the relevant Charter Guarantor  notice(s) specifying the amounts for which Parent, the Partnership and/or its subsidiaries are entitled to indemnification under Section 1.4 and this Section 1.6 and Charter Guarantor shall indemnify Parent and the relevant subsidiaries for any losses, damages, liabilities, claims, demands, causes of action, judgments, settlements, fines, penalties, costs and expenses (including, without limitation, court costs and reasonable attorneys’ and experts’ fees, as incurred) of any and every kind or character arising out of or related to such Charter Guarantor’s failure to comply with such Charter Guarantor’s obligations.

Section 1.7.         Subrogation.  With respect to any amount paid by Parent pursuant to Section 1.1(ii) and (iii) or Section 1.4, the relevant Charter Guarantor shall on and from the date of any such payment assign to Parent any rights of contribution or subrogation against the Partnership and, as applicable, its subsidiaries corresponding to such amount.

Section 1.8.         Cooperation.  On and from the Effective Time, GP Parent and Parent shall use reasonable endeavors to have the Charter Guarantors removed as guarantor or counter-indemnifier, as the case may be, under the Covered Agreements.

Section 1.9.        Indemnification in Respect of Eskimo and Tundra.  From the date hereof until the termination of the Eskimo Bareboat Charter and full and unconditional release, satisfaction or discharge of all obligations contained therein, (a) GP Parent shall indemnify, defend and hold harmless Parent and each of its Affiliates from and against all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees) arising in connection with the occurrence of a Termination Event (as defined in the Eskimo Bareboat Charter) pursuant to Clause 44.1(ff) of the Eskimo Bareboat Charter, and (b) Parent shall indemnify, defend and hold harmless GP Parent and each of its Affiliates from and against all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees) arising in connection with the occurrence of a Termination Event (as defined in the Tundra Bareboat Charter) pursuant to Clause 44.1(ff) of the Tundra Bareboat Charter.

Section 1.10.       Financial Information. GP Parent shall provide to Parent the unaudited quarterly management accounts and audited financial statements that are required to be provided to the Owner (as defined in the Hilli Bareboat Charter) pursuant to clauses 49(a) and 49(b) of the Hilli Bareboat Charter at the same time such accounts and financial statements are provided to the Owner. Parent shall provide to GP Parent the unaudited quarterly management accounts and audited financial statements that are required to be provided to the Owner (as defined in the Hilli Bareboat Charter) pursuant to clauses 49(a) and 49(b) of the Hilli Bareboat Charter at the same time such accounts and financial statements are provided to the Owner.

Section 1.11.       Methane Princess.Unless the Methane Princess is delivered to 2215 Lessee on the date hereof free and clear of all liens other than Permitted Encumbrances (as defined in, and only to the extent permitted to remain after Closing under, the Merger Agreement) following the advancement and application of the Prepayment and Repayment Funds (as defined in the Closing Payment Funding Letter) and the consummation of the Closing (as defined in the Merger Agreement), GP Parent agrees that (i) the advancement and application of the Prepayment and Repayment Funds (as defined in the Closing Payment Funding Letter) will not give rise to any claim for breach or right of termination under the MP Time Charter by Methane Services Limited or BG International Limited, (ii) none of the advancement and payments made under the Closing Payment Funding Letter or the Merger Agreement will give rise to any tax liability not covered in the Tax Indemnity Agreement (as defined in the GP Transfer Agreement), which GP Parent and Parent are entering into concurrently with the execution of this Agreement, and (iii) GP Parent is liable for any taxes for which 2215 Lessee is otherwise liable under Sections 5.5 and 5.6 of the Sale Agreement in respect of the Methane Princess between 2215 Lessee and A&L CF June (3) Limited (the “MP Sale Agreement”). If the Methane Princess has not been delivered to 2215 Lessee on the date hereof free and clear of all liens other than Permitted Encumbrances (as defined in, and only to the extent permitted to remain after Closing under, the Merger Agreement) following the advancement and application of the Prepayment and Repayment Funds (as defined in the Closing Payment Funding Letter) and the consummation of the Closing (as defined in the Merger Agreement), or if 2215 Lessee becomes liable for taxes under Section 5.5 and/or 5.6 of the MP Sale Agreement, then GP Parent shall indemnify, defend and hold harmless Parent and each of its Affiliates from and against all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees) arising in connection with any failure of the foregoing statements in this Section 1.11 (i), (ii) and (iii), as applicable, to be true and correct.

Section 1.12.       GP Parent Indemnification in Respect of GP Parent Hilli Bareboat Charter Guarantee and Standard Chartered Bank Guarantee. GP Parent agrees that it shall (i) maintain (x) its several guarantee in respect of the Hilli Bareboat Charter (the “GP Parent Hilli Bareboat Charter Guarantee”) in accordance with the terms of the Hilli Bareboat Charter and (y) the Guarantee dated 29 November 2016 in favor of Standard Chartered Bank (“SCB”) issued pursuant to the facility letter between SCB and Golar Hilli Corporation (the “GP Parent SCB Guarantee”), and (ii) comply with all covenants and terms to which GP Parent is subject in the GP Parent Hilli Bareboat Charter Guarantee and the GP Parent SCB Guarantee. GP Parent shall indemnify, defend and hold harmless Parent and each of its Affiliates from and against all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees) arising in connection with a failure by GP Parent to comply with the foregoing.

Section 1.13.      Parent Indemnification in Respect of Partnership Hilli Bareboat Charter Guarantee and Standard Chartered Bank Guarantee and Hilli Parent Undertaking. Parent agrees that it shall (i) (x) procure that the Partnership maintains its several guarantee in respect of the Hilli Bareboat Charter (the “Partnership Hilli Bareboat Charter Guarantee”) in accordance with the terms of the Hilli Bareboat Charter, (y) procure that the Partnership maintains the Guarantee dated 28 November 2018 in favor of SCB issued pursuant to the facility letter between SCB and Golar Hilli Corporation (the “Partnership SCB Guarantee”) and (z) issue an undertaking, in favor of Fortune, to discharge the liabilities of the Partnership under the Hilli Bareboat Charter, in the event that Partnership does not do so (the “Hilli Parent Undertaking”), (ii) comply with the Hilli Parent Undertaking and  (iii) procure that the Partnership complies with all covenants and terms to which the Partnership is subject in the Partnership Hilli Bareboat Charter Guarantee and the Partnership SCB Guarantee.  Parent shall indemnify, defend and hold harmless GP Parent and each of its Affiliates from and against all losses, liabilities, damages, costs and expenses of every kind and nature (including reasonable attorneys’ fees) arising in connection with a failure by Parent to comply with the foregoing.

ARTICLE II

MANAGEMENT AGREEMENTS

Section 2.1.       Amendment and Restatement.  All management agreements and management services agreements between Owners and Tier 1 Service Provider shall be amended and restated on and from the Effective Time in the form appended at Schedule B (such amended and restated management agreements being the “Tier 1 Management Agreements”) provided that in the event of any conflict between any term of a Tier 1 Management Agreement and this Article II, this Article II shall prevail.

Section 2.2.         Manager Termination Right. Without prejudice to any express right of termination a Tier 1 Service Provider or Tier 2 Service Providers has to terminate any management agreement, including, without limitation, pursuant to Clause 22 of the relevant Tier 1 Management Agreement ,to which it is a party (such agreements together the “Tier 1/Tier 2 Management Agreements”) in accordance with the terms of such management agreement, in exercising any express right to terminate for convenience under a management agreement, including, without limitation, pursuant to Clause 21 of the relevant Tier 1 Management Agreement, each Tier 1 Service Provider or Tier 2 Service Provider shall , except to the extent that (i) the vessel to which such Tier 1/Tier 2 Management Agreement relates continues to be the subject of a time charter party agreement, an FSRU lease agreement, a liquefaction tolling agreement or gas agreement (together the “Charter Contracts”) and (ii) where such management agreement termination would reasonably be expected to trigger a termination right relating to the change in the identity of the manager of the relevant vessel under its Charter Contract, be entitled to exercise such right to terminate any Tier 1/Tier 2 Management Agreement by giving sixty (60) days’ notice to the relevant Owner (such termination, a “Manager Termination Right for Convenience”).

Section 2.3.        Owner Termination Right.  Owner may terminate any Tier 1 Management Agreement for its convenience by giving sixty (60) days’ notice to the Tier 1 Service Provider.

Section 2.4.         Limitation on Liability.  Any provision of a Tier 1/Tier 2 Management Agreement that would, but for this Section 2.4, have the effect of capping or limiting the liability of the Tier 1 Service Provider or a Tier 2 Service Provider thereunder, as the case may be, shall not apply in the event that such Tier 1/Tier 2 Management Agreement is terminated by a Tier 1 Service Provider or Tier 2 Service Provider (i) pursuant to any Manager Termination Right for Convenience which does not comply with Section 2.2 of this Agreement or (ii) in a manner that is not expressly contemplated in such Tier 1/Tier 2 Management Agreement (as amended by Section 2.2 of this Agreement, where such management agreement termination triggers a termination right relating to the change in the identity of the manager of the relevant vessel under its Charter Contract).

Section 2.5.        Services Provision. Subject to the terms hereof and the relevant Tier 1/Tier 2 Management Agreements,  the Tier 1 Service Provider and the Tier 2 Service Providers will continue to provide such services as are set out in, and in accordance with, the relevant Tier 1/Tier 2 Management Agreements and any other management agreements to which the Tier 2 Service Providers are a party, and the consultancy services under the Tier 1 Management Agreement shall without limitation include such advisory or other additional services as may be reasonably requested by the Partnership to enable the Owners to comply with each Charter Contract and any related financing arrangement covenant relating to management service provision, change of control and ownership, in each case as relate to the transaction contemplated by the Merger Agreement and this Agreement.

ARTICLE III

MISCELLANEOUS

Section 3.1.          Choice of Law; Submission to Jurisdiction.  This Agreement shall be subject to and governed by the laws of the State of New York.

Section 3.2.         Notice.  All notices, requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing the same in the mail, addressed to the Person to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by private-courier, prepaid, by telecopier to such party or by e-mail to such party.  Notice given by personal delivery or mail shall be effective upon actual receipt.  Couriered notices shall be deemed delivered on the date the courier represents that delivery will occur.  Notice given by e-mail or telecopier shall be effective upon actual receipt if received during the recipient’s normal business hours, or at the beginning of the recipient’s next business day after receipt if not received during the recipient’s normal business hours.  All notices to be sent to a party pursuant to this Agreement shall be sent to or made at the address set forth below such party’s signature to this Agreement, or at such other address as such party may stipulate to the other parties in the manner provided in this Section 3.2.

Section 3.3.         Entire Agreement.  This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding all prior contracts or agreements, whether oral or written, relating to the matters contained herein.

Section 3.4.        Termination.  This Agreement shall terminate at the latest to occur of (a) no GP Parent Guarantee or GP LC Counter-indemnity remaining outstanding, (b) each of Parent and the Charter Guarantors has paid all amounts due pursuant to Article I, (c) the termination of all Covered Documents, (d) the termination of all management agreements and management services agreements to which the Tier 1 Service Provider and Tier 2 Service Providers are a party, (e) the termination of (i) the Eskimo Bareboat Charter, and (ii) the Hilli Bareboat Charter, and (f) the expiration of the “Charter Period” under the MP Time Charter.

Section 3.5.          Amendment or Modification.  This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto.

Section 3.6.          Assignment.  No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto.

Section 3.7.          Counterparts.  This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document.  All counterparts shall be construed together and shall constitute one and the same instrument.

Section 3.8.          Severability.  If any provision of this Agreement or the application thereof to any Person or circumstance shall be held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

Section 3.9.         Gender, Parts, Articles and Sections.  Whenever the context requires, the gender of all words used in this Agreement shall include the masculine, feminine and neuter, and the number of all words shall include the singular and plural.  All references to Article numbers and Section numbers refer to Articles and Sections of this Agreement.

Section 3.10.       Further Assurances.  In connection with this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement.

[Signature page follows.]

IN WITNESS WHEREOF, the Parties have executed this Agreement on, and effective as of, the date first written above.

GOLAR LNG LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director
Address for Notice for the GP Parent, the GEL Parent, the Tier 1 Service Provider and the Tier 2 Service Providers:
Golar Management Ltd
6th Floor, The Zig Zag
70 Victoria Street
London SW1E 6SQ
United Kingdom
Email:	karl.staubo@golar.com GMLLegal@golar.com
Attention: Karl Fredrik Staubo

NEW FORTRESS ENERGY, INC.
By:	/s/ Christopher Guinta
	Name:	Christopher Guinta
	Title:	Director
Address for Notice for the Parent and the Owners:
New Fortress Energy Inc.
111 W. 19th Street, 8th Floor
New York, New York 10011
Attn:	General Counsel
Email:	legal@newfortressenergy.com
Phone:	516-268-7400

GOLAR LNG ENERGY LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

GOLAR ESKIMO CORPORATION
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

GOLAR FREEZE UK LTD
By:	/s/ Malcolm Bulbeck
	Name:	Malcolm Bulbeck
	Title:	Director

GOLAR HULL M2031 CORP.
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

GOLAR WINTER UK LTD
By:	/s/ Malcolm Bulbeck
	Name:	Malcolm Bulbeck
	Title:	Director

PT GOLAR INDONESIA
By:	/s/ Osman Ilyas
	Name:	Osman Ilyas
	Title:	Director

GOLAR 2215 UK LTD
By:	/s/ Malcolm Bulbeck
	Name:	Malcolm Bulbeck
	Title:	Director

GOLAR GRAND CORPORATION
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

GOLAR LNG 2234 LLC
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

FARAWAY MARITIME SHIPPING COMPANY
By:	/s/ Erling David-Andersen
	Name:	Erling David-Andersen
	Title:	Director

GOLAR SPIRIT CORPORATION
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

GOLAR MANAGEMENT (BERMUDA) LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

GOLAR MANAGEMENT LTD
By:	/s/ Malcolm Bulbeck
	Name:	Malcolm Bulbeck
	Title:	Director

GOLAR MANAGEMENT NORWAY AS
By:	/s/ Erling David-Andersen
	Name:	Erling David-Andersen
	Title:	Director

GOLAR MANAGEMENT D.O.O.
By:	/s/ Lasse Røed
	Name:	Lasse Røed
	Title:	Director

GOLAR MANAGEMENT MALAYSIA SDN BHD
By:	/s/ Jamal Ishak Aziz Ahmad
	Name:	Jamal Ishak Aziz Ahmad
	Title:	General Manager

GOLAR CAMEROON SASU
By:	/s/ Aubry Vincent
	Name:	Aubry Vincent
	Title:	GM

Schedule A

Covered Agreements

1. Time Charter Party dated as of September 4, 2007 between Petroleo Brasileiro S.A., as Charterer, and Golar Winter UK Limited, as Owner in respect of the Golar Winter.

2. FSRU Lease Agreement between The Government of the Hashemite Kingdom of Jordan and Golar Eskimo Corporation, dated as of July 31, 2013 in respect of the Golar Eskimo, as novated to National Electric Power Company.

3. Time Charter Party (as novated and restated) in respect of Hull No. 2215, dated as of August 27, 2003, between Methane Services Limited and Golar 2215 UK Ltd in respect of the Methane Princess.

4. Time Charter Party dated as of April 20, 2011 between PT Nusantara Regas, as charterer, and PT Golar Indonesia (further to a Novation Agreement dated April 12, 2012) in respect of the Nusantara Regas Satu, as novated to PT Golar Indonesia.

5. Hilli LTA Guarantee Facility with SCB.

Schedule B1

BIMCO Shipman Agreement to be inserted

Schedule B2

Bermuda Services Agreement to be inserted

Schedule C

Management Agreements

Tier 1 Management Agreements

Asset	Golar Counterparty / Owner	Tier 1 Service Provider
Eskimo	Golar Eskimo Corporation	GML
Freeze	Golar Freeze UK Ltd	GML
Igloo	Golar Hull M2031 Corporation	GML
Winter	Golar Winter UK Ltd	GML
NR Satu	PT Golar Indonesia	GML
Methane Princess	Golar 2215 UK Ltd	GML
Grand	Golar Grand Corporation	GML
Maria	Golar LNG 2234 LLC	GML
Mazo	Faraway Maritime Shipping Company	GML
Spirit	Golar Spirit Corporation	GML
Corporate	Golar LNG Partners LP	Golar Management (Bermuda) Limited

Tier 2 Management Agreements

Counterparty	Service Provider
GML	Golar Management Norway AS
GML	Golar Management Malaysia SDN BHD
GML	Golar Management D.O.O.
Golar Hilli Corporation	Golar Cameroon SASU
Golar Golar Hilli Corporation	Golar Management Ltd

Schedule D

Parties

Golar LNG Limited, a Bermuda exempted company (“GP Parent”), Golar LNG Energy Limited (“GEL Parent” and with GP Parent, the “Charter Guarantors”), Golar Eskimo Corporation, a Marshall Islands corporation (“Golar Eskimo”), Golar Freeze UK Ltd, an England and Wales company (“Golar Freeze”), Golar Hull M2031 Corp., a Marshall Islands corporation (“Golar M2031”), Golar Winter UK Ltd, an England and Wales company (“Golar Winter”), PT Golar Indonesia, an Indonesia company (“Golar Indonesia”), Golar 2215 UK Ltd, an England and Wales company (“Golar 2215”), Golar Grand Corporation, a Marshall Islands corporation (“Golar Grand”), Golar LNG 2234 LLC, a Liberia limited liability company (“Golar 2234”),  Faraway Maritime Shipping Company, a Liberia corporation (“Faraway Shipping”), Golar Spirit Corporation, a Marshall Islands corporation (“Golar Spirit” and together with Golar Eskimo, Golar Freeze, Golar M2031, Golar Winter, Golar Indonesia, Golar 2215, Golar Grand, Golar 2234, Faraway Shipping and Golar Spirit, the “Owners”), Golar Management Ltd (“GML”), an England and Wales company, (the “Tier 1 Service Provider”), Golar Management Norway AS, a Norway company (“Goman Norway”), Golar Management Malaysia SDN BHD, a Malaysia company (“Goman Malaysia”), Golar Management D.O.O., a Croatia company (“Goman Croatia”), Golar Management (Bermuda) Limited, a Bermuda exempted company (“Golar Management Bermuda”), Golar Cameroon SASU, a Cameroon company (“Golar Cameroon, and together with GML, Goman Norway, Goman Malaysia, Golar Cameroon and Goman Croatia, the “Tier 2 Service Providers”) and New Fortress Energy Inc., a Delaware corporation (“Parent” and together with the Charter Guarantors, the Owners, the Tier 1 Service Provider and the Tier 2 Service Providers, the “Parties”).

EX-10.33

Exhibit 10.33

Execution Version

TAX INDEMNIFICATION AGREEMENT

THIS TAX INDEMNIFICATION AGREEMENT (“Agreement”), dated as of April 15, 2021, is by and among Golar LNG Limited, a Bermuda exempted company (“Indemnitor”), and NFE International Holdings Limited, a private limited company incorporated under the laws of England and Wales, United Kingdom (“Purchaser”).

W I T N E S S E T H

WHEREAS, Indemnitor, directly or through one or more Subsidiaries, has entered into one or more sale and leaseback transactions with certain lessor entities that are tax reacasidents of or otherwise subject to tax in the United Kingdom (together with their respective successors and permitted assigns, “Lessors”), pursuant to which Indemnitor sold certain vessels to a Lessor, and the applicable Lessor leased back such vessels to Indemnitor or its Affiliates, including Subsidiaries of Golar LNG Partners LP, a Marshall Islands limited partnership (the “Company”) (the “UK Tax Lease Transactions”);

WHEREAS, under the terms of the UK Tax Lease Transactions, in the event of any adverse tax changes or a successful challenge by certain tax authorities with regard to certain aspects of the UK Tax Lease Transactions, the Company or its affiliates may be required to make additional payments to the applicable Lessor or one or more entities that are or were Affiliates of one or more of the Lessors;

WHEREAS, Indemnitor is the owner of 100% of the limited liability company membership interests in Golar GP LLC, a Marshall Islands limited liability company (the “GP”), including all rights and obligations relating thereto and all economic and capital interest therein;

WHEREAS, the GP is the sole general partner of the Company;

WHEREAS, New Fortress Energy Inc., a Delaware corporation (“Parent”) and the GP have entered into that certain Agreement and Plan of Merger, dated as of January 13, 2021 (the “Merger Agreement”) by and among the Company, the GP, Parent, and Lobos Acquisition LLC, a Marshall Islands limited liability company (“Merger Sub”), pursuant to which Merger Sub will merge with and into the Company as a result of which Purchaser will own certain interests in the Company;

WHEREAS, Purchaser and the Indemnitor have entered into that certain Transfer Agreement, dated as of January 13, 2021 (the “GP Transfer Agreement”), pursuant to which Purchaser is acquiring all of the equity interests in the GP;

WHEREAS, in connection with the transactions contemplated by the Merger Agreement and the GP Transfer Agreement (the “Acquisition”), Indemnitor desires to indemnify and hold harmless Purchaser, its Affiliates (including, after the Closing, the Company and its Subsidiaries), and certain other parties from any Losses (as defined herein) arising from the UK Tax Lease Transactions; and

WHEREAS, any capitalized term used but not defined herein shall have the respective meanings ascribed to such term in the Merger Agreement.

NOW, THEREFORE, in consideration of the foregoing, the parties hereto agree as follows:

ARTICLE I

INDEMNIFICATION AND COVENANTS

Section 1.1          Indemnification. Indemnitor shall indemnify, defend and hold harmless Purchaser, Parent, Merger Sub, and each of their respective Affiliates (including, for the avoidance of doubt, following the Closing, the GP, the Company, and each of the Company’s Subsidiaries) and each of their respective Representatives (collectively, the “Indemnitees”) from and against any and all losses, damages, liabilities, costs (including without limitation, legal costs on a full indemnity basis), charges, fees, expenses, Taxes, disbursements, actions, penalties, proceedings, claims and demands or other liabilities in any case of any nature whatsoever (collectively, “Losses”), to the extent based upon, arising out of, relating to or resulting from any of the following (each an “Indemnified Obligation”):

(a)          any guarantee or indemnification obligation to any Lessor or any current, past, or future Affiliate of any Lessor based upon, arising out of, relating to or resulting from any UK Tax Lease Transaction;

(b)          any letter of credit provided to, or for the benefit of, any Lessor or any current, past, or future Affiliate of any Lessor based upon, arising out of, relating to or resulting from any UK Tax Lease Transaction;

(c)          any mortgage, lien, or other security interest granted in favor of any Lessor or any current, past, or future Affiliate of any Lessor with respect to any vessel that is owned, leased, or operated by the Company or its Subsidiaries, based upon, arising out of, relating to or resulting from any UK Tax Lease Transaction (each a “Security Interest”);

(d)          any audit, examination, contest, investigation, claim or other Proceeding in respect of any Taxes or Tax Returns (each a “Tax Action”) based upon, arising out of, relating to, or resulting from any UK Tax Lease Transaction; or

(e)          any deficiency for any Tax proposed, threatened, asserted, or assessed by any Governmental Authority based upon, arising out of, relating to or resulting from any UK Tax Lease Transaction.

Section 1.2           Covenants.

(a)          Indemnitor shall, at its own cost and expense, prior to the Closing, obtain a release and discharge of each Security Interest from each holder thereof; and

(b)          Indemnitor shall cause Golar Hilli LLC, a Marshall Islands limited liability company (“Hilli”) to make an election under Section 754 of the Code (and any corresponding election under state or local Law) effective for the taxable year ending December 31, 2020, if such an election is not already in effect with respect to Hilli.

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Section 1.3       Cooperation. From and after the Closing, Indemnitor and Purchaser shall, and shall cause their respective Affiliates and Representatives to, reasonably cooperate in connection with the preparation and filing of any Tax Return, the conduct of any Tax Action, or determining a liability for Taxes or a right to a refund of Taxes, in each case with respect to an Indemnified Obligation, which cooperation shall include (a) supplying any information in such Person’s possession that is reasonably requested in connection with any such Tax Return, Tax Action or Tax liability or refund, and (b) making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder.

Section 1.4           Indemnification Procedures.

(a)          Each Indemnitee shall, within a reasonable period of time after such Indemnitee become aware of facts giving rise to an Indemnified Obligation (a “UK Tax Lease Claim”), provide notice thereof in writing to Indemnitor specifying the nature of and specific basis for such UK Tax Lease Claim.

(b)          Indemnitor shall have the right to control all aspects of the defense of (and any counterclaims with respect to) any claims brought against any Indemnitee that are UK Tax Lease Claims, including, without limitation, the selection of counsel, determination of whether to appeal any decision of any court and the settling of any such matter or any issues relating thereto; provided, however, that no such settlement shall be entered into without the consent (which consent shall not be unreasonably withheld) of the applicable Indemnitee(s) unless it includes a full release of such Indemnitee(s) from such matter or issues, as the case may be.

(c)          Each Indemnitee shall cooperate fully with Indemnitor with respect to all aspects of the defense of any UK Tax Lease Claim, including, without limitation, the prompt furnishing to Indemnitor of any correspondence or other notice relating thereto that such Indemnitee may receive, permitting the names of such Indemnitee to be utilized in connection with such defense, the making available to Indemnitor of any files, records or other information of such Indemnitee that Indemnitor considers relevant to such defense and the making available to Indemnitor of any employees of such Indemnitee; provided, however, that in connection therewith Indemnitor agrees to use reasonable efforts to minimize the impact thereof on the operations of each Indemnitee and further agrees to maintain the confidentiality of all files, records and other information furnished by an Indemnitee pursuant to this Section 1.4(c). In no event shall the obligation of an Indemnitee to cooperate with Indemnitor as set forth in the immediately preceding sentence be construed as imposing upon any Indemnitee an obligation to hire and pay for counsel in connection with the defense of any UK Tax Lease Claim; provided, however, that each Indemnitee may, at its own option, cost and expense, hire and pay for counsel in connection with any such defense. Indemnitor agrees to keep any such counsel hired by any Indemnitee reasonably informed as to the status of any such defense (including providing such counsel with such information related to any such defense as such counsel may reasonably request) but Indemnitor shall have the right to retain sole control over such defense.

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(d)          In determining the amount of any Loss for which any Indemnitee is entitled to indemnification with respect to a UK Tax Lease Claim, the gross amount of such indemnification will be reduced by (i) any insurance proceeds realized by the Indemnitees, and such correlative insurance benefit shall be net of any incremental insurance premium that becomes due and payable by any Indemnitee as a result of such claim, and (ii) all amounts recovered by the Indemnitees under contractual indemnities from third Persons. The Purchaser hereby agrees to use commercially reasonable efforts to realize any applicable insurance proceeds or amounts recoverable under such contractual indemnities; provided, however, that the costs and expenses (including, without limitation, court costs and reasonable attorneys’ fees) of each Indemnitee in connection with such efforts shall be promptly reimbursed by Indemnitor in advance of any determination of whether such insurance proceeds or other amounts will be recoverable.

Section 1.5          Survival; Conflicts.  Notwithstanding anything to the contrary in the Merger Agreement or the GP Transfer Agreement, the covenants and agreements of the parties contained in this Agreement shall survive indefinitely.  To the extent of any conflict or inconsistency between the provisions of this Agreement and the provisions of the Merger Agreement or the GP Transfer Agreement, the provisions of this Agreement shall control.

Section 1.6           Adjustment to Purchase Price.  Any payment under this Agreement shall be treated for all applicable Tax purposes as an adjustment to the Common Unit Consideration received by Indemnitor, except as otherwise required pursuant to a final determination (within the meaning of Section 1313(a) of the Code) or similar determination under applicable state, local or non-U.S. Tax Law. If, at any time, any applicable Law, regulation or regulatory requirement imposes any Tax in respect of any payment made by Indemnitor in respect of a claim by an Indemnitee under an Indemnified Obligation, Indemnitor shall pay to such Indemnitee an additional amount sufficient to ensure that the amount received by such Indemnitee on the due date for such payment equals the full amount that would have been received by such Indemnitee if such Tax had not been imposed. Indemnitor and Purchaser shall reasonably cooperate to minimize the imposition of any such Taxes.

ARTICLE II

MISCELLANEOUS

Section 2.1          Amendment or Supplement. This Agreement may be amended or supplemented in any and all respects by written agreement of the parties hereto, by action taken by their respective Boards of Directors.

Section 2.2          Extension of Time, Waiver, Etc. Purchaser and Indemnitor may, subject to applicable Law, (a) extend the time for the performance of any of the obligations or acts of the other party or (b) subject to the requirements of applicable Law, waive compliance by the other party with any of the agreements contained herein or, except as otherwise provided herein, waive any of such party’s conditions. Notwithstanding the foregoing, no failure or delay by Indemnitor or any Indemnitee in exercising any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right hereunder. Any agreement on the part of a party hereto to any such extension or waiver shall be valid only if set forth in an instrument in writing signed on behalf of such party.

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Section 2.3           Assignment.

(a)          Neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned, in whole or in part, by operation of Law or otherwise, by any of the parties hereto without the prior written consent of the other parties hereto; provided, however, Purchaser may assign all or any of its rights and obligations hereunder to any Affiliate.

(b)          No assignment by any party shall relieve such party of any of its obligations hereunder. Subject to clause (a) above and the first section of this clause (b), this Agreement shall be binding upon, inure to the benefit of, and be enforceable by, the parties hereto and their respective successors and permitted assigns. Any purported assignment not permitted under this Section 2.3 shall be null and void.

Section 2.4          Counterparts. This Agreement may be executed in one or more counterparts (including by facsimile or electronic mail), each of which shall be deemed to be an original but all of which taken together shall constitute one and the same agreement, and shall become effective when one or more counterparts have been signed by each of the parties hereto and delivered to the other parties hereto.

Section 2.5      Entire Agreement; No Third-Party Beneficiaries. This Agreement (a) constitutes the entire agreement, and supersede all other prior agreements and understandings, both written and oral, among the parties hereto and their Affiliates, or any of them, with respect to the subject matter hereof and (b) is not intended to and shall not confer upon any Person other than the parties hereto and each Indemnitee any rights or remedies hereunder.

Section 2.6          Governing Law. This Agreement shall be governed by, interpreted under, and construed and enforced in accordance with, the laws of the State of Delaware.

Section 2.7        WAIVER OF JURY TRIAL. EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT ISSUES, AND THEREFORE IT HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT AND ANY OF THE AGREEMENTS DELIVERED IN CONNECTION HEREWITH OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY. EACH PARTY CERTIFIES AND ACKNOWLEDGES THAT (A) NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, (B) IT UNDERSTANDS AND HAS CONSIDERED THE IMPLICATIONS OF SUCH WAIVER, (C) IT MAKES SUCH WAIVER VOLUNTARILY AND (D) IT HAS BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVER AND CERTIFICATIONS IN THIS SECTION 2.7.

Section 2.8          Remedies. Except as otherwise provided in this Agreement, any and all remedies expressly conferred upon a party to this Agreement shall be cumulative with, and not exclusive of, any other remedy contained in this Agreement, at law or in equity. The exercise by a party to this Agreement of any one remedy shall not preclude the exercise by it of any other remedy.

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Section 2.9        Notices. All notices, requests and other communications to any party hereunder shall be in writing and shall be deemed given if delivered personally, facsimiled (which is confirmed by email), emailed (which is confirmed by facsimile) or sent by overnight courier (providing proof of delivery) to the parties at the following addresses:

If to Purchaser:

New Fortress Energy Inc.

111 W. 19th Street, 8th Floor

New York, New York 10011

Attn:      Cameron D. MacDougall

Email:    cmacdougall@fortress.com

with a copy (which shall not constitute notice) to:

Skadden, Arps, Slate, Meagher & Flom LLP

One Manhattan West

New York, New York 10001

Attention:            Joseph A. Coco

Facsimile:           212-735-2000

Email:                  joseph.coco@skadden.com

Attention:            Thomas W. Greenberg

Facsimile:            212-735-2000

Email:                  thomas.greenberg@skadden.com

Skadden, Arps, Slate, Meagher & Flom LLP

1000 Louisiana St., Suite 6800

Houston, TX 77002

Attention:            Eric C. Otness

Facsimile:            713-483-9135

Email:                  eric.ottness@skadden.com

If to Indemnitor, to:

Golar LNG Limited

2nd Floor, S.E. Pearman Building

9 Par-la-Ville Road

Hamilton HM 11, Bermuda

Attention:            Karl Staubo

Facsimile:            +44 (0)207 063 7901

Email:                  karl.staubo@golar.com

GMLLegal@golar.com

6

with copies (which shall not constitute notice) to:

Baker Botts L.L.P.

30 Rockefeller Plaza

New York, New York 10112

Attention:            Michael Swidler

Facsimile:            212-259-2511

Email:                  michael.swidler@bakerbotts.com

Baker Botts L.L.P.

700 K Street, N.W.

Washington, DC 20001

Attention:            Catherine Gallagher

Email:                  catherine.gallagher@bakerbotts.com

or such other address, email address or facsimile number as such party may hereafter specify by like notice to the other parties hereto. All such notices, requests and other communications shall be deemed received on the date of actual receipt by the recipient thereof if received prior to 5:00 p.m. local time in the place of receipt and such day is a Business Day in the place of receipt. Otherwise, any such notice, request or communication shall be deemed not to have been received until the next succeeding Business Day in the place of receipt.

Section 2.10        Severability. If any term, condition or other provision of this Agreement is determined by a court of competent jurisdiction to be invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other terms, provisions and conditions of this Agreement shall nevertheless remain in full force and effect. Upon such determination that any term, condition or other provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate to attempt to modify this Agreement so as to effect the original intent of the parties as closely as possible to the fullest extent permitted by applicable Law in an acceptable manner.

Section 2.11        Fees and Expenses. Except as otherwise set forth in this Agreement, whether or not the Acquisition is consummated, (i) all fees and expenses incurred by Purchaser in connection with this Agreement shall be paid by Purchaser and (ii) all fees and expenses incurred by Indemnitor in connection with this Agreement shall be paid by Indemnitor.

[Signature Page Follows]

7

IN WITNESS WHEREOF, the parties hereto have caused this Tax Indemnification Agreement to be duly executed and delivered as of the date first above written.

GOLAR LNG LIMITED
By:	/s/ Georgina E. Sousa
	Name:	Georgina E. Sousa
	Title:	Director

[Signature Page – Tax Indemnification Agreement]

NFE INTERNATIONAL HOLDINGS LIMITED
By:	/s/ Christopher Guinta
	Name:	Christopher Guinta
	Title:	Director

[Signature Page – Tax Indemnification Agreement]

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934

I, Wesley R. Edens, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q (the “report”) of New Fortress Energy Inc. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2021	By:		/s/ Wesley R. Edens
			Wesley R. Edens
			Chief Executive Officer
			(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934

I, Christopher S. Guinta, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q (the “report”) of New Fortress Energy Inc. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

c. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	May 7, 2021	By:		/s/ Christopher S. Guinta
			Christopher S. Guinta
			Chief Financial Officer
			(Principal Financial Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER UNDER SECTION 906

OF THE SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with the Quarterly Report on Form 10-Q of New Fortress Energy Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Wesley R. Edens, Chief Executive Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 7, 2021	By:		/s/ Wesley R. Edens
			Wesley R. Edens
			Chief Executive Officer
			(Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER UNDER SECTION 906

OF THE SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

In connection with Quarterly Report on Form 10-Q of New Fortress Energy Inc. (the “Company”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Christopher S. Guinta, Chief Financial Officer of the Company, certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	May 7, 2021	By:		/s/ Christopher S. Guinta
			Christopher S. Guinta
			Chief Financial Officer
			(Principal Financial Officer)

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2021	May 03, 2021
Cover [Abstract]
Entity Registrant Name	New Fortress Energy Inc.
Entity Central Index Key	0001749723
Current Fiscal Year End Date	--12-31
Document Type	10-Q
Amendment Flag	false
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Document Transition Report	false
Entity File Number	001-38790
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	83-1482060
Entity Address, Address Line One	111 W. 19th Street
Entity Address, Address Line Two	8th Floor
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10011
City Area Code	516
Local Phone Number	268-7400
Title of 12(b) Security	Class A common stock
Trading Symbol	NFE
Security Exchange Name	NASDAQ
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		206,698,564

XML

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 360,130	$ 601,522
Restricted cash	4,072	12,814
Receivables, net of allowances of $203 and $98, respectively	95,729	76,544
Inventory	28,031	22,860
Prepaid expenses and other current assets, net	60,245	48,270
Total current assets	548,207	762,010
Restricted cash	15,000	15,000
Construction in progress	337,691	234,037
Property, plant and equipment, net	607,003	614,206
Right-of-use assets	131,575	141,347
Intangible assets, net	65,934	46,102
Finance leases, net	7,501	7,044
Deferred tax assets, net	5,060	2,315
Other non-current assets, net	114,140	86,030
Total assets	1,832,111	1,908,091
Current liabilities
Accounts payable	27,970	21,331
Accrued liabilities	88,809	90,352
Current lease liabilities	34,857	35,481
Due to affiliates	10,859	8,980
Other current liabilities	33,375	35,006
Total current liabilities	195,870	191,150
Long-term debt	1,239,799	1,239,561
Non-current lease liabilities	74,363	84,323
Deferred tax liabilities, net	5,194	2,330
Other long-term liabilities	25,704	15,641
Total liabilities	1,540,930	1,533,005
Commitments and contingences (Note 17)
Stockholders' equity
Additional paid-in capital	551,135	594,534
Accumulated deficit	(267,406)	(229,503)
Accumulated other comprehensive income	59	182
Total stockholders' equity attributable to NFE	285,534	366,959
Non-controlling interest	5,647	8,127
Total stockholders' equity	291,181	375,086
Total liabilities and stockholders' equity	1,832,111	1,908,091
Class A Common Stock [Member]
Stockholders' equity
Class A common stock, $0.01 par value, 750.0 million shares authorized, 175.3 million issued and outstanding as of March 31, 2021; 174.6 million issued and outstanding as of December 31, 2020	$ 1,746	$ 1,746

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Current assets
Allowances for receivables	$ 203	$ 98
Class A Common Stock [Member]
Stockholders' equity
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	750,000,000.0	750,000,000.0
Common stock, shares issued (in shares)	175,300,000	174,600,000
Shares outstanding (in shares)	175,320,414	174,600,000

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Condensed Consolidated Statements of Operations and Comprehensive Loss - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Revenues
Operating revenue	$ 91,196	$ 63,502
Other revenue	54,488	11,028
Total revenues	145,684	74,530
Operating expenses
Cost of sales	96,671	68,216
Operations and maintenance	16,252	8,483
Selling, general and administrative	45,181	28,538
Contract termination charges and loss on mitigation sales	0	208
Depreciation and amortization	9,890	5,254
Total operating expenses	167,994	110,699
Operating loss	(22,310)	(36,169)
Interest expense	18,680	13,890
Other (income) expense, net	(604)	611
Loss on extinguishment of debt, net	0	9,557
Loss before taxes	(40,386)	(60,227)
Tax benefit	(877)	(4)
Net loss	(39,509)	(60,223)
Net loss attributable to non-controlling interest	1,606	51,757
Net loss attributable to stockholders	$ (37,903)	$ (8,466)
Net loss per share - basic (in dollars per share)	$ (0.21)	$ (0.32)
Net loss per share - diluted (in dollars per share)	$ (0.21)	$ (0.32)
Weighted average number of shares outstanding - basic (in shares)	176,500,576	26,029,492
Weighted average number of shares outstanding - diluted (in shares)	176,500,576	26,029,492
Other comprehensive loss:
Net loss	$ (39,509)	$ (60,223)
Currency translation adjustment	997	369
Comprehensive loss	(40,506)	(60,592)
Comprehensive loss attributable to non-controlling interest	2,480	52,073
Comprehensive loss attributable to stockholders	$ (38,026)	$ (8,519)

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Condensed Consolidated Statements of Changes in Stockholders' Equity - USD ($) $ in Thousands	Common Stock [Member] Class A Shares [Member]	Common Stock [Member] Class B Shares [Member]	Common Stock [Member] Class A Common Stock [Member]	Additional Paid-in Capital [Member]	Accumulated Deficit [Member]	Accumulated Other Comprehensive (Loss) Income [Member]	Non-controlling Interest [Member]	Total	Cumulative Effect, Period of Adoption, Adjustment [Member] Common Stock [Member] Class A Shares [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Common Stock [Member] Class B Shares [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Common Stock [Member] Class A Common Stock [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Additional Paid-in Capital [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Accumulated Deficit [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Accumulated Other Comprehensive (Loss) Income [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member] Non-controlling Interest [Member]	Cumulative Effect, Period of Adoption, Adjustment [Member]
Balance at Dec. 31, 2019	$ 130,658	$ 0	$ 0	$ 0	$ (45,823)	$ (30)	$ 302,519	$ 387,324
Balance (ASC 842 [Member]) at Dec. 31, 2019									$ 0	$ 0	$ 0	$ 0	$ (1,533)	$ 0	$ (7,780)	$ (9,313)
Balance (in shares) at Dec. 31, 2019	23,607,096	144,342,572	0
Balance (in shares) (ASC 842 [Member]) at Dec. 31, 2019									0	0	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	$ 0	$ 0	$ 0	0	(8,466)	0	(51,757)	(60,223)
Other comprehensive loss	0	0	0	0	0	(53)	(316)	(369)
Share-based compensation expense	2,508	0	0	0	0	0	0	2,508
Issuance of shares for vested RSUs	$ 0	$ 0	$ 0	0	0	0	0	0
Issuance of shares for vested RSUs (in shares)	1,212,907	0	0
Shares withheld from employees related to share-based compensation, at cost	$ (6,132)	$ 0	$ 0	0	0	0	0	(6,132)
Shares withheld from employees related to share-based compensation, at cost (in shares)	(583,508)	0	0
Balance at Mar. 31, 2020	$ 127,034	$ 0	$ 0	0	(55,822)	(83)	242,666	313,795
Balance (in shares) at Mar. 31, 2020	24,236,495	144,342,572	0
Balance at Dec. 31, 2020	$ 0	$ 0	$ 1,746	594,534	(229,503)	182	8,127	375,086
Balance (in shares) at Dec. 31, 2020	0	0	174,622,862
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	$ 0	$ 0	$ 0	0	(37,903)	0	(1,606)	(39,509)
Other comprehensive loss			0	0	0	(123)	(874)	(997)
Share-based compensation expense			0	1,770	0	0	0	1,770
Issuance of shares for vested RSUs	$ 0	$ 0	$ 0	0	0	0	0	0
Issuance of shares for vested RSUs (in shares)	0	0	1,335,787
Shares withheld from employees related to share-based compensation, at cost	$ 0	$ 0	$ 0	(27,571)	0	0	0	(27,571)
Shares withheld from employees related to share-based compensation, at cost (in shares)	0	0	(638,235)
Dividends	$ 0	$ 0	$ 0	(17,598)	0	0	0	(17,598)
Balance at Mar. 31, 2021	$ 0	$ 0	$ 1,746	$ 551,135	$ (267,406)	$ 59	$ 5,647	$ 291,181
Balance (in shares) at Mar. 31, 2021	0	0	175,320,414

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Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Cash flows from operating activities
Net loss	$ (39,509)	$ (60,223)
Adjustments for:
Amortization of deferred financing costs	400	3,353
Depreciation and amortization	10,160	5,481
Loss on extinguishment and financing expenses	0	9,557
Deferred taxes	(1,412)	(18)
Share-based compensation	1,770	2,508
Other	393	2,656
Changes in operating assets and liabilities:
(Increase) Decrease in receivables	(19,223)	5,752
(Increase) Decrease in inventories	(5,171)	34,830
(Increase) in other assets	(36,943)	(54,080)
Decrease in right-of-use assets	9,772	9,263
(Decrease) Increase in accounts payable/accrued liabilities	(22,399)	2,132
Increase (Decrease) in amounts due to affiliates	1,879	(2,875)
(Decrease) in lease liabilities	(10,584)	(9,170)
(Decrease) in other liabilities	(1,119)	(477)
Net cash used in operating activities	(111,986)	(51,311)
Cash flows from investing activities
Capital expenditures	(80,810)	(56,098)
Entities acquired in asset acquisitions, net of cash acquired	(8,817)	0
Other investing activities	(630)	50
Net cash used in investing activities	(90,257)	(56,048)
Cash flows from financing activities
Proceeds from borrowings of debt	0	832,144
Payment of deferred financing costs	(670)	(14,069)
Repayment of debt	0	(506,402)
Payments related to tax withholdings for share-based compensation	(29,564)	(6,084)
Payment of dividends	(17,657)	0
Net cash (used in) provided by financing activities	(47,891)	305,589
Net (decrease) increase in cash, cash equivalents and restricted cash	(250,134)	198,230
Cash, cash equivalents and restricted cash - beginning of period	629,336	93,035
Cash, cash equivalents and restricted cash - end of period	379,202	291,265
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	26,311	13,359
Liabilities associated with consideration paid for entities acquired in asset acquisitions	$ 11,845	$ 0

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Organization

3 Months Ended

Mar. 31, 2021

Organization [Abstract]

Organization

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.

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Significant accounting policies

3 Months Ended

Mar. 31, 2021

Significant accounting policies [Abstract]

Significant accounting policies

2. Significant accounting policies

The principal accounting policies adopted are set out below.

(a) Basis of presentation and principles of consolidation

The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with GAAP and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. The condensed 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. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020.

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 condensed 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.

Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s condensed 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 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 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 condensed 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 March 31, 2021, NFE had 175,320,414 Class A common stock outstanding.

(b) Revenue recognition

The Company’s contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from 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.

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 condensed 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 condensed 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 condensed 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 condensed consolidated statements of operations and comprehensive loss.

In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes 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 condensed consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed 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 condensed 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 condensed 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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Adoption of new and revised standards

3 Months Ended

Mar. 31, 2021

Adoption of new and revised standards [Abstract]

Adoption of new and revised standards

3. Adoption of new and revised standards

(a) New standards, amendments and interpretations issued but not effective for the financial year beginning January 1, 2021:

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 December 2019, 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 adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

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Revenue from contracts with customers

3 Months Ended

Mar. 31, 2021

Revenue from contracts with customers [Abstract]

Revenue from contracts with customers

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 March 31, 2021 and December 31, 2020, receivables related to revenue from contracts with customers totaled $95,753 and $76,431, respectively, and were included in Receivables, net on the condensed consolidated balance sheets, net of current expected credit losses of $203 and $98, 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.

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 condensed 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 March 31, 2021 and December 31, 2020 are detailed below:

	March 31, 2021		December 31, 2020
Contract assets, net-current	$	5,268	$	3,673
Contract assets, net-non-current		30,685		23,972
Total contract assets, net	$	35,953	$	27,645
Contract liabilities	$	10,704	$	8,399
Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year	$	942	$	6,542

Contract assets are presented net of expected credit losses of $484 and $372 as of March 31, 2021 and December 31, 2020, respectively. As of March 31, 2021, the Company has unbilled receivables, net of current expected credit losses, of $6,729, of which $356 is presented within Other current assets and $6,373 is presented within Other non-current assets on the condensed consolidated balance sheet. 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 $91,196 and $63,502 for the three months ended March 31, 2021 and 2020, respectively.

Other revenue includes revenue for development services as well as lease and other revenue. The table below summarizes the balances in Other revenue:

	Three Months Ended March 31,
	2021		2020
Development services revenue	$	54,071	$	10,071
Lease and other revenue		417		957
Total other revenue	$	54,488	$	11,028

Development services revenue recognized in the three months ended March 31, 2021 included $45,618 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.

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 $10,478,395 as of March 31, 2021, 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
Remainder of 2021	$	278,546
2022		504,522
2023		504,708
2024		499,842
2025		494,081
Thereafter		8,196,696
Total	$	10,478,395

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 March 31, 2021, the Company has capitalized $11,434 of which $604 of these costs is presented within Other current assets and $10,830 is presented within Other non-current assets on the condensed consolidated balance sheets. As of December 31, 2020, the Company had capitalized $11,276, of which $588 of these costs was presented within Other current assets and $10,688 was presented within Other non-current assets on the condensed 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.

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Leases

3 Months Ended

Mar. 31, 2021

Leases [Abstract]

Leases

5. Leases

Lessee

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 three months ended March 31, 2021 and 2020, the Company’s operating lease cost recorded within the condensed consolidated statements of operations and comprehensive loss were as follows:

	Three Months Ended March 31,
	2021		2020
Fixed lease cost	$	11,745	$	10,267
Variable lease cost		693		639
Short-term lease cost		722		286
Lease cost - Cost of sales	$	11,036	$	9,351
Lease cost - Operations and maintenance		557		388
Lease cost - Selling, general and administrative		1,567		1,453

For the three months ended March 31, 2021, the Company has capitalized $1,199 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 condensed consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the three months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021		2020
Operating cash outflows for operating lease liabilities	$	12,660	$	10,096
Right-of-use assets obtained in exchange for new operating lease liabilities		-		127,994

The future payments due under operating leases as of March 31, 2021 are as follows:

	Operating Leases
Due remainder of 2021	$	30,754
2022		29,931
2023		18,719
2024		17,866
2025		10,680
Thereafter		50,019
Total lease payments		157,969
Less: effects of discounting		48,749
Present value of lease liabilities	$	109,220
Current lease liability	$	34,857
Non-current lease liability		74,363

As of March 31, 2021, the weighted-average remaining lease term for all operating leases was 7.3 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 March 31, 2021 was 8.4%.

The Company has entered into several leases for ISO tanks and an office space that have not commenced as of March 31, 2021 with noncancelable terms of 5 years and including fixed payments of approximately $24 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:

	March 31, 2021			December 31, 2020
Property, plant and equipment	$	18,747		$	18,394
Accumulated depreciation		(1,189	)		(932	)
Property, plant and equipment, net	$	17,558		$	17,462

The following table shows the expected future lease payments as of March 31, 2021, for the remainder of 2021 through 2025 and thereafter:

	Future cash receipts
	Financing leases		Operating leases
Remainder of 2021	$	1,671	$	220
2022		2,149		286
2023		2,134		288
2024		2,135		273
2025		2,001		234
Thereafter		5,705		743
Total	$	15,795	$	2,044
Less: Imputed interest		6,718
Present value of total lease receipts	$	9,077
Current finance leases, net	$	1,576
Non-current finance leases, net		7,501

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Fair value

3 Months Ended

Mar. 31, 2021

Fair value [Abstract]

Fair value

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 March 31, 2021 and December 31, 2020:

	March 31, 2021
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets
Cash and cash equivalents	$	360,130	$	-	$	-	$	360,130	Market approach
Restricted cash		19,072		-		-		19,072	Market approach
Investment in equity securities		294		-		1,849		2,143	Market approach
Total	$	379,496	$	-	$	1,849	$	381,345
Liabilities
Derivative liability¹	$	-	$	-	$	20,692	$	20,692	Income approach
Equity agreement²		-		-		21,223		21,223	Income approach
Total	$	-	$	-	$	41,915	$	41,915

	December 31, 2020
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets
Cash and cash equivalents	$	601,522	$	-	$	-	$	601,522	Market approach
Restricted cash		27,814		-		-		27,814	Market approach
Investment in equity securities		256		-		1,000		1,256	Market approach
Total	$	629,592	$	-	$	1,000	$	630,592
Liabilities
Derivative liability¹	$	-	$	-	$	10,716	$	10,716	Income approach
Equity agreement²		-		-		22,768		22,768	Income approach
Total	$	-	$	-	$	33,484	$	33,484

⁽¹⁾ Consideration due to the sellers in assets acquistions when certain contingent events occur.

⁽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 to the derivative liability and equity agreement, recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss, and currency translation adjustment, recorded within the Other comprehensive loss, for the three months ended March 31, 2021 and 2020:

	March 31, 2021			March 31, 2020
Fair value adjustment - (Gain)	$	(425	)	$	(1,617	)
Currency translation adjustment - (Gain)		(1,664	)		(537	)

Activity during the three months ended March 31, 2021 included the recognition of additional derivative liabilities from transactions accounted for as asset acquisitions of $10,520 (Note 21. Asset acquisitions). During the three months ended March 31, 2021 and 2020, the Company had no settlements of the equity agreement or derivative liabilities or any transfers in or out of Level 3 in the fair value hierarchy.

The liability associated with the equity agreement of $21,223 and $22,768 as of March 31, 2021 and December 31, 2020, respectively, is recorded within Other current liabilities on the condensed consolidated balance sheets. The liability associated with the derivative liabilities of $20,692 and $10,716 as of March 31, 2021 and December 31, 2020, respectively, is recorded within Other long-term liabilities on the condensed consolidated balance sheets.

The Company estimates fair value of outstanding debt using quoted market prices. The fair value of the 2025 Notes (defined below in Note 15. Debt) was approximately $1,285,588 as of March 31, 2021. The fair value estimate is classified as Level 2 in the fair value hierarchy.

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Restricted cash

3 Months Ended

Mar. 31, 2021

Restricted cash [Abstract]

Restricted cash

7. Restricted cash

As of March 31, 2021 and December 31, 2020, restricted cash consisted of the following:

	March 31, 2021		December 31, 2020
Collateral for performance under customer agreements	$	15,000	$	15,000
Collateral for LNG purchases		2,916		11,664
Collateral for letters of credit and performance bonds		906		900
Other restricted cash		250		250
Total restricted cash	$	19,072	$	27,814
Current restricted cash	$	4,072	$	12,814
Non-current restricted cash		15,000		15,000

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Inventory

3 Months Ended

Mar. 31, 2021

Inventory [Abstract]

Inventory

8. Inventory

As of March 31, 2021 and December 31, 2020, inventory consisted of the following:

	March 31, 2021		December 31, 2020
LNG and natural gas inventory	$	18,213	$	13,986
Automotive diesel oil inventory		4,463		3,986
Bunker fuel, materials, supplies and other		5,355		4,888
Total inventory	$	28,031	$	22,860

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 condensed consolidated statements of operations and comprehensive loss. No adjustments were recorded during the three months ended March 31, 2021 and 2020.

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Prepaid expenses and other current assets

3 Months Ended

Mar. 31, 2021

Prepaid expenses and other current assets [Abstract]

Prepaid expenses and other current assets

9. Prepaid expenses and other current assets

As of March 31, 2021 and December 31, 2020, prepaid expenses and other current assets consisted of the following:

	March 31, 2021		December 31, 2020
Prepaid LNG	$	20,605	$	11,987
Prepaid expenses		6,806		4,941
Due from affiliates (Note 20)		1,912		1,881
Other current assets		30,922		29,461
Total prepaid expenses and other current assets, net	$	60,245	$	48,270

Other current assets as of March 31, 2021 and December 31, 2020 primarily consists of receivables for recoverable taxes.

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Construction in progress

3 Months Ended

Mar. 31, 2021

Construction in progress [Abstract]

Construction in progress

10. Construction in progress

The Company’s construction in progress activity during the three months ended March 31, 2021 is detailed below:

	March 31, 2021
Balance at beginning of period	$	234,037
Additions		105,761
Transferred to property, plant and equipment, net or finance leases		(2,107	)
Balance at end of period	$	337,691

Interest expense of $2,641 and $9,606, inclusive of amortized debt issuance costs, was capitalized for the three months ended March 31, 2021 and 2020, respectively.

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Property, plant and equipment, net

3 Months Ended

Mar. 31, 2021

Property, plant and equipment, net [Abstract]

Property, plant and equipment, net

11. Property, plant and equipment, net

As of March 31, 2021 and December 31, 2020, the Company’s property, plant and equipment, net consisted of the following:

	March 31, 2021			December 31, 2020
Terminal and power plant equipment	$	189,197		$	188,855
CHP facilities		119,723			119,723
Gas terminals		120,810			120,810
ISO containers and other equipment		102,010			100,137
LNG liquefaction facilities		63,213			63,213
Gas pipelines		58,974			58,974
Land		16,582			16,246
Leasehold improvements		8,723			8,723
Accumulated depreciation		(72,229	)		(62,475	)
Total property, plant and equipment, net	$	607,003		$	614,206

Depreciation for the three months ended March 31, 2021 and 2020 totaled $9,842 and $5,211, respectively, of which $270 and $227, respectively, is included within Cost of sales in the condensed consolidated statements of operations and comprehensive loss.

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Intangible assets

3 Months Ended

Mar. 31, 2021

Intangible assets [Abstract]

Intangible assets

12. Intangible assets

The following table summarizes the composition of intangible assets as of March 31, 2021 and December 31, 2020:

	March 31, 2021
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Permits	$	49,467	$	2,607	$	46,860		38
Acquired power purchase agreements		16,499		-		16,499		17
Easements		1,559		203		1,356		30
Indefinite-lived intangible assets
Easements		1,219		-		1,219		n/a
Total intangible assets	$	68,744	$	2,810	$	65,934

	December 31, 2020
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
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

During the first quarter of 2021, the Company recognized additions to permits of $5,776 acquired in a transaction accounted for as asset acquisition related to licenses and rights to develop a gas-fired power plant and associated infrastructure in the Port of Suape in Brazil. The Company also acquired rights operated a power generation facility and sell power in Brazil of $16,585 (see Note 21. Asset acquisitions).

As of March 31, 2021 and December 31, 2020, the weighted-average remaining amortization periods for the intangible assets were 31.0 and 37.5 years, respectively. Amortization expense for the three months ended March 31, 2021 and 2020 totaled $295 and $270, respectively.

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Other non-current assets

3 Months Ended

Mar. 31, 2021

Other non-current assets [Abstract]

Other non-current assets

13. Other non-current assets

As of March 31, 2021 and December 31, 2020, Other non-current assets consisted of the following:

	March 31, 2021		December 31, 2020
Nonrefundable deposit	$	30,728	$	28,509
Contract asset, net (Note 4)		30,685		23,972
Cost to fulfill (Note 4)		10,830		10,688
Unbilled receivables, net (Note 4)		6,373		6,462
Upfront payments to customers		10,501		6,330
Other		25,023		10,069
Total other non-current assets, net	$	114,140	$	86,030

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 issuance costs associated with the 2026 Notes and Revolving Facility (both defined below) that closed in April 2021, 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”).  During the first quarter of 2021, the investee completed a qualified financing which converted the Company’s investment into preferred shares; the Company also invested an additional $750 in this qualified financing.

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Accrued liabilities

3 Months Ended

Mar. 31, 2021

Accrued liabilities [Abstract]

Accrued liabilities

14. Accrued liabilities

As of March 31, 2021 and December 31, 2020, accrued liabilities consisted of the following:

	March 31, 2021		December 31, 2020
Accrued development costs	$	25,222	$	16,631
Accrued interest		3,516		27,938
Accrued bonuses		6,171		17,344
Other accrued expenses		53,900		28,439
Total accrued liabilities	$	88,809	$	90,352

Other accrued expenses includes accrued legal, accounting and other transaction costs associated with the Mergers and the issuance of the 2026 Notes and the Revolving Facility (all defined below).

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Debt

3 Months Ended

Mar. 31, 2021

Debt [Abstract]

Debt

15. Debt

As of March 31, 2021 and December 31, 2020, debt consisted of the following:

	March 31, 2021		December 31, 2020
Senior Secured Notes, due September 15, 2025	$	1,239,799	$	1,239,561
Total debt	$	1,239,799	$	1,239,561

2025 Notes

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

The 2025 Notes are guaranteed, jointly and severally, by certain of the Company’s subsidiaries, in addition to other collateral. The 2025 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 2025 Notes also provide for customary events of default and prepayment provisions.

The Company used a portion of the net cash proceeds received from the 2025 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 2025 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 2025 Notes on the condensed consolidated balance sheets; unamortized deferred financing costs related to lenders in the Credit Agreement that participated in the 2025 Notes were $6,501 and such unamortized costs were also included as a reduction of the principal balance of the 2025 Notes and will be amortized over the remaining term of the 2025 Notes. As a portion of the repayment of the Credit Agreement was a modification, in the third quarter of 2020, the Company recorded $4,028 of third-party fees in Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss.

On December 17, 2020, the Company issued $250,000 of additional notes on the same terms as the 2025 Notes in a private offering pursuant to Rule 144A under the Securities Act (subsequent to this issuance, these additional notes are included in the definition of 2025 Notes herein). Proceeds received included a premium of $13,125, which was offset by additional financing costs incurred of $4,436. As of March 31, 2021, total remaining unamortized deferred financing costs for all outstanding debt were $10,201.

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.

In connection with obtaining the Credit Agreement and the extinguishment of the Term Loan Facility, the Company incurred $37,051 in origination, structuring and other fees which were recognized as a reduction of the principal balance of the Credit Agreement on the condensed consolidated balance sheets.

On September 2, 2020, the Company repaid the full amount outstanding using proceeds from the 2025 Notes. Certain lenders in the Credit Agreement participated in the issuance of 2025 Notes, and a portion of the repayment of the Credit Agreement was treated as a debt modification. For the portion of the Credit Agreement that was considered extinguished, $16,310 of unamortized deferred debt issuance costs was recognized as a loss on extinguishment of debt in the condensed consolidated statements of operations and comprehensive loss. The remaining unamortized deferred debt issuance costs of $6,501 will be amortized over the remaining term of the 2025 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 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 condensed 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 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.

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 condensed consolidated balance sheets. On September 21, 2020, the Company repaid the full amount outstanding including fees dues to the lenders using proceeds from the 2025 Notes and cash on hand. In conjunction with the repayment of the Senior Secured Bonds and Senior Unsecured Bonds in the third quarter of 2020, the Company recognized a loss on extinguishment of debt of $7,195, including the write-off of $3,594 of unamortized deferred financing costs and prepayment premium paid to bondholders of $3,601.

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 three months ended March 31, 2021 and 2020 consisted of the following:

	Three Months Ended March 31,
	2021		2020
Interest per contractual rates	$	20,834	$	18,874
Amortization of debt issuance costs		487		4,622
Total interest costs		21,321		23,496
Capitalized interest		2,641		9,606
Total interest expense	$	18,680	$	13,890

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Income taxes

3 Months Ended

Mar. 31, 2021

Income taxes [Abstract]

Income taxes

16. Income taxes

In the third quarter of 2020, the Company completed the Conversion; 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.

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. Prior to the Exchange Transactions, NFI was a limited liability company that was treated as a partnership 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. 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. 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.

In the first quarter of 2021, the Company contributed all NFI LLC units into a wholly owned corporate entity, which had the effect of terminating NFI LLC’s treatment as a partnership for U.S. federal income tax purposes. The transaction does not have a material impact on income tax expense.

The effective tax rate for the three months ended March 31, 2021 was 2.2%, compared to 0.01% for the three months ended March 31, 2020. The total tax benefit for the three months ended March 31, 2021 was $877, compared to $4 for the three months ended March 31, 2020, and the increase in benefit for the three months ended March 31, 2021 was primarily driven by the release of a valuation allowance in a foreign jurisdiction resulting in a discrete benefit of $3,010 partially offset by income tax expense recorded for certain profitable non-U.S. operations.

The primary items which decreased the Company’s effective tax rate for the three months ended March 31, 2021 and March 31, 2020 from the U.S. federal statutory rate of 21% were valuation allowances recorded against a portion of the Company’s current period losses and earnings generated in non-U.S. jurisdictions with lower tax rates.

The Company has not recorded a liability for uncertain tax positions as of March 31, 2021. The Company remains subject to periodic audits and reviews by the taxing authorities, and NFE’s returns since its formation remain open for examination.

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Commitments and contingencies

3 Months Ended

Mar. 31, 2021

Commitments and contingencies [Abstract]

Commitments and contingencies

17. Commitments and 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.

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Earnings per share

3 Months Ended

Mar. 31, 2021

Earnings per share [Abstract]

Earnings per share

18. Earnings per share

	Three Months Ended March 31,
	2021			2020
Numerator:
Net loss	$	(39,509	)	$	(60,223	)
Less: net loss attributable to non-controlling interests		1,606			51,757
Net loss attributable to Class A common stock	$	(37,903	)	$	(8,466	)
Denominator:
Weighted-average shares-basic and diluted		176,500,576			26,029,492
Net loss per share - basic and diluted	$	(0.21	)	$	(0.32	)

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.

	Three Months Ended March 31,
	2021		2020
Unvested RSUs1		869,262		1,890,125
Class B shares2		-		144,342,572
Shannon Equity Agreement shares3		464,267		1,635,462
Total		1,333,529		147,868,159

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. In connection with the closing of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares.

³ Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

The Company declared dividends of $17,598 ($0.10 per share); during the first quarter of 2021, the Company paid $17,657 of dividends, inclusive of dividends that were accrued in prior periods.

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Share-based compensation

3 Months Ended

Mar. 31, 2021

Share-based compensation [Abstract]

Share-based compensation

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 New Fortress Energy Inc. 2019 Omnibus 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 three months ended March 31, 2021:

	Restricted Share Units			Weighted-average grant date fair value per share
Non-vested RSUs as of December 31, 2020		1,538,060		$	13.49
Granted		-			-
Vested		(665,781	)		13.54
Forfeited		(3,017	)		13.51
Non-vested RSUs as of March 31, 2021		869,262		$	13.45

The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the three  months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021		2020
Operations and maintenance	$	222	$	237
Selling, general and administrative		1,548		2,271
Total share-based compensation expense	$	1,770	$	2,508

For the three months ended March 31, 2021 and 2020, cumulative compensation expense recognized for forfeited RSU awards of $0 and $61, 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 March 31, 2021, the Company had 869,262 non-vested RSUs subject to service conditions and had unrecognized compensation costs of approximately $6,400. 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 1.05 years as of March 31, 2021.

Performance Share Units (“PSUs”)

During the first quarter of 2020 and 2021, the Company granted PSUs to certain employees and non-employees that contain a performance condition. Vesting will be determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. For the three months ended March 31, 2021, 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 condensed consolidated statements of operations and comprehensive loss

PSUs Granted	Units Granted	Range of Vesting	Unrecognized Compensation Cost(1)		Weighted Average Remaining Vesting Period
Q1 2020	1,109,777	0 to 2,219,554	$	30,864	0.75 years
Q1 2021	400,507	0 to 801,014	$	32,577	1.75 years

(1) Unrecognized compensation cost is based upon the maximum amount of shares that could vest

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Related party transactions

3 Months Ended

Mar. 31, 2021

Related party transactions [Abstract]

Related party transactions

20. 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 Administrative Agreement that are attributable to the Company totaled $1,927 and $2,231 for the three months ended March 31, 2021 and 2020, respectively. Costs associated with the Administrative Agreement are included within Selling, general and administrative in the condensed consolidated statements of operations and comprehensive loss. As of March 31, 2021 and December 31, 2020, $7,145 and $5,535 were due to Fortress, respectively.

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 $1,609 and $1,239 for the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, $554 and $472 was due to this affiliate, respectively.

Land lease

The Company has leased land from Florida East Coast Industries, LLC (“FECI”), which is controlled by funds managed by an affiliate of Fortress. The Company recognized expense related to the land lease of $126 and $103 during the three months ended March 31, 2021 and 2020, respectively, which was included within Operations and maintenance in the condensed consolidated statements of operations and comprehensive loss. As of March 31, 2021 and December 31, 2020, $0 and $316 was due to FECI, respectively. As of March 31, 2021, the Company has recorded a lease liability of $3,288 within Non-current lease liabilities on the condensed 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 condensed consolidated financial statements. DevTech purchased 10% of a note payable due to an affiliate of the Company. As of March 31, 2021 and December 31, 2020, $715 was owed to DevTech on the note payable, and the outstanding note payable due to DevTech is included in Other long-term liabilities on the condensed consolidated balance sheets. The interest expense on the note payable due to DevTech was $21 and $19 for the three months ended March 31, 2021 and 2020, respectively. No interest has been paid, and accrued interest has been recognized within Other current liabilities on the condensed consolidated balance sheets. As of March 31, 2021 and December 31, 2020, $343 was due from DevTech.

Fortress affiliated entities

Since 2017, the Company has provided certain administrative services to related parties including Fortress affiliated entities. As of March 31, 2021 and December 31, 2020, $1,210 and $1,334 were due from affiliates, respectively. There are no costs incurred by the Company as the Company is fully reimbursed for all costs incurred. Beginning in the fourth quarter of 2020, the Company began to sublease a portion of office space to an affiliate of an entity managed by Fortress, and for the three months ended March 31, 2021, $153 of rent and office related expenses were incurred by this affiliate. As of March 31, 2021 and December 31, 2020, $359 and $204 were due from this affiliate, respectively.

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 $803 and $1,165 for the three months ended March 31, 2021 and 2020, respectively. As of March 31, 2021 and December 31, 2020, $3,160 and $2,657 were due to Fortress affiliated entities, respectively.

Due to/from Affiliates

The table below summarizes the balances outstanding with affiliates as of March 31, 2021 and December 31, 2020:

	March 31, 2021		December 31, 2020
Amounts due to affiliates	$	10,859	$	8,980
Amounts due from affiliates		1,912		1,881

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Asset acquisitions

3 Months Ended

Mar. 31, 2021

Asset acquisitions [Abstract]

Asset acquisitions

21. Asset acquisitions

On January 12, 2021, the Company acquired 100% of the outstanding share quota of CH4 Energia Ltda. ("CH4"), an entity that owns key permits and authorizations to develop an LNG terminal and an up to 1.37GW gas-fired power plant at the Port of Suape in Brazil. The purchase consideration consisted of $903 of cash paid at closing in addition to potential future payments contingent on achieving certain construction milestones of up to $3,600. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments of $3,047 is included as part of the purchase consideration and is recognized in Other non-current liabilities on the condensed consolidated balance sheet as of March 31, 2021. The selling shareholders of CH4 may also receive future payments based on gas consumed by the power plant or sold to customers from the LNG terminal.

The purchase of CH4 has been accounted for as an asset acquisition. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $295 are included in the purchase consideration. The total purchase consideration of $4,245 was allocated to permits and authorizations acquired and is recorded within Intangible assets, net. In addition, the Company recognized a deferred tax liability of $1,531 that resulted from the acquisition.

On March 11, 2021, the Company acquired 100% of the outstanding shares of Pecém Energia S.A. (“Pecém”) and Energetica Camacari Muricy II S.A. (“Muricy”). These companies collectively hold grants to operate as an independent power provider and 15-year power purchase agreements for the development of thermoelectric power plants in the State of Bahia, Brazil. The Company is seeking to obtain the necessary approvals to transfer the power purchase agreements in connection with the construction the gas-fired power plant and LNG import terminal at the Port of Suape.

The purchase consideration consisted of $8,041 of cash paid at closing in addition to potential future payments contingent on achieving commercial operations of the gas-fired power plant at the Port of Suape of up to approximately $10.5 million. As the contingent payments meet the definition of a derivative, the fair value of the contingent payments of $7,473 was included as part of the purchase consideration and is recognized in Other non-current liabilities on the condensed consolidated balance sheet as of March 31, 2021. The selling shareholders may also receive future payments based on power generated by the power plant in Suape, subject to a maximum payment of approximately $4.6 million.

The purchases of Pecém and Muricy were accounted for as asset acquisitions. As a result, no goodwill was recorded, and the Company’s acquisition-related costs of $1,275 were included in the purchase consideration. Of the total purchase consideration, $16,585 was allocated to acquired power purchase agreements and recorded in Intangibles on the condensed consolidated balance sheet; the remaining purchase consideration was related to working capital acquired.

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Subsequent events

3 Months Ended

Mar. 31, 2021

Subsequent events [Abstract]

Subsequent events

22. Subsequent events

On April 12, 2021, the Company completed the private offering of $1.5 billion aggregate principal amount of senior secured notes due 2026 (the “2026 Notes”). The 2026 Notes bear interest at 6.50% per annum and were issued at an issue price equal to 100% of principal. The 2026 Notes are guaranteed on a senior secured basis by each domestic subsidiary and foreign subsidiary that is a guarantor under the existing 2025 Notes, and the 2026 Notes are secured by substantially the same collateral as the Company’s existing first lien obligations under the 2025 Notes. The Company used the net proceeds from this offering to fund the cash consideration for the GMLP Merger and pay related fees and expenses.

On April 15, 2021, the Company completed the previously announced acquisitions of Hygo Energy Transition Ltd. (“Hygo”) and Golar LNG Partners LP (“GMLP”); referred to as the “Hygo Merger” and “GMLP Merger,” respectively  and, collectively, the “Mergers”. NFE paid $580 million in cash and issued 31,372,549 shares of Class A common stock to Hygo’s shareholders in connection with the Hygo Merger. NFE paid $3.55 per each common unit of GMLP outstanding and for each of the outstanding membership interests of GMLP’s general partner, totaling $251 million. The Company also repaid certain outstanding debt facilities of GMLP in conjunction with closing the GMLP Merger.

These transactions will be accounted for as business combinations under the acquisition method of accounting. The Company will record the assets acquired and liabilities assumed at their fair values as of the acquisition date. Due to the limited time since the closing of the acquisitions, the valuation efforts and related acquisition accounting are incomplete at the time of filing of the condensed consolidated financial statements.

On April 15, 2021, we entered into a $200 million senior secured revolving facility (the “Revolving Facility”). The 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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Significant accounting policies (Policies)

3 Months Ended

Mar. 31, 2021

Significant accounting policies [Abstract]

Basis of presentation and principles of consolidation

(a) Basis of presentation and principles of consolidation

The accompanying unaudited interim condensed consolidated financial statements contained herein were prepared in accordance with GAAP and reflect all normal and recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the financial position, results of operations and cash flows of the Company for the interim periods presented. The condensed 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. These condensed consolidated financial statements and accompanying notes should be read in conjunction with the Company’s annual consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020.

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 condensed 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.

Prior to the Exchange Transactions, the Company recognized the Exchanging Members’ economic interest in NFI as non-controlling interest in the Company’s condensed 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 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 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 condensed 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 March 31, 2021, NFE had 175,320,414 Class A common stock outstanding.

Revenue recognition

(b) Revenue recognition

The Company’s contracts with customers may contain one or several performance obligations usually consisting of the sale of LNG, natural gas, power and steam, which are outputs from 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.

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 condensed 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 condensed 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 condensed 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 condensed consolidated statements of operations and comprehensive loss.

In addition to the revenue recognized from the leasing components of agreements with customers, Other revenue includes 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 condensed consolidated balance sheets. Contract liabilities consist of deferred revenue and are recognized within Other current liabilities on the condensed 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 condensed 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 condensed 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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Revenue from contracts with customers (Tables)

3 Months Ended

Mar. 31, 2021

Revenue from contracts with customers [Abstract]

Contract with Customer, Asset and Liability

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 condensed 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 March 31, 2021 and December 31, 2020 are detailed below:

	March 31, 2021		December 31, 2020
Contract assets, net-current	$	5,268	$	3,673
Contract assets, net-non-current		30,685		23,972
Total contract assets, net	$	35,953	$	27,645
Contract liabilities	$	10,704	$	8,399
Revenue recognized in the year from:
Amounts included in contract liabilities at the beginning of the year	$	942	$	6,542

Other Revenue

Other revenue includes revenue for development services as well as lease and other revenue. The table below summarizes the balances in Other revenue:

	Three Months Ended March 31,
	2021		2020
Development services revenue	$	54,071	$	10,071
Lease and other revenue		417		957
Total other revenue	$	54,488	$	11,028

Remaining Performance Obligations

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 $10,478,395 as of March 31, 2021, 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
Remainder of 2021	$	278,546
2022		504,522
2023		504,708
2024		499,842
2025		494,081
Thereafter		8,196,696
Total	$	10,478,395

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Leases (Tables)

3 Months Ended

Mar. 31, 2021

Leases [Abstract]

Components of Operating Lease Costs

For the three months ended March 31, 2021 and 2020, the Company’s operating lease cost recorded within the condensed consolidated statements of operations and comprehensive loss were as follows:

	Three Months Ended March 31,
	2021		2020
Fixed lease cost	$	11,745	$	10,267
Variable lease cost		693		639
Short-term lease cost		722		286
Lease cost - Cost of sales	$	11,036	$	9,351
Lease cost - Operations and maintenance		557		388
Lease cost - Selling, general and administrative		1,567		1,453

Supplemental Cash Flow Information Related to Leases

Cash paid for operating leases is reported in operating activities in the condensed consolidated statements of cash flows. Supplemental cash flow information related to leases was as follows for the three months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021		2020
Operating cash outflows for operating lease liabilities	$	12,660	$	10,096
Right-of-use assets obtained in exchange for new operating lease liabilities		-		127,994

Future Payments Due under Operating Leases

The future payments due under operating leases as of March 31, 2021 are as follows:

	Operating Leases
Due remainder of 2021	$	30,754
2022		29,931
2023		18,719
2024		17,866
2025		10,680
Thereafter		50,019
Total lease payments		157,969
Less: effects of discounting		48,749
Present value of lease liabilities	$	109,220
Current lease liability	$	34,857
Non-current lease liability		74,363

Property, Plant and Equipment Subject to Operating Leases

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:

	March 31, 2021			December 31, 2020
Property, plant and equipment	$	18,747		$	18,394
Accumulated depreciation		(1,189	)		(932	)
Property, plant and equipment, net	$	17,558		$	17,462

Operating and Financing Lease Payments to be Received

The following table shows the expected future lease payments as of March 31, 2021, for the remainder of 2021 through 2025 and thereafter:

	Future cash receipts
	Financing leases		Operating leases
Remainder of 2021	$	1,671	$	220
2022		2,149		286
2023		2,134		288
2024		2,135		273
2025		2,001		234
Thereafter		5,705		743
Total	$	15,795	$	2,044
Less: Imputed interest		6,718
Present value of total lease receipts	$	9,077
Current finance leases, net	$	1,576
Non-current finance leases, net		7,501

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Fair value (Tables)

3 Months Ended

Mar. 31, 2021

Fair value [Abstract]

Financial Assets and Financial Liabilities

The following table presents the Company’s financial assets and financial liabilities that are measured at fair value as of March 31, 2021 and December 31, 2020:

	March 31, 2021
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets
Cash and cash equivalents	$	360,130	$	-	$	-	$	360,130	Market approach
Restricted cash		19,072		-		-		19,072	Market approach
Investment in equity securities		294		-		1,849		2,143	Market approach
Total	$	379,496	$	-	$	1,849	$	381,345
Liabilities
Derivative liability¹	$	-	$	-	$	20,692	$	20,692	Income approach
Equity agreement²		-		-		21,223		21,223	Income approach
Total	$	-	$	-	$	41,915	$	41,915

	December 31, 2020
	Level 1		Level 2		Level 3		Total		Valuation technique
Assets
Cash and cash equivalents	$	601,522	$	-	$	-	$	601,522	Market approach
Restricted cash		27,814		-		-		27,814	Market approach
Investment in equity securities		256		-		1,000		1,256	Market approach
Total	$	629,592	$	-	$	1,000	$	630,592
Liabilities
Derivative liability¹	$	-	$	-	$	10,716	$	10,716	Income approach
Equity agreement²		-		-		22,768		22,768	Income approach
Total	$	-	$	-	$	33,484	$	33,484

⁽¹⁾ Consideration due to the sellers in assets acquistions when certain contingent events occur.

⁽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.

Fair Value and Currency Translation Adjustment

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 to the derivative liability and equity agreement, recorded within Other (income) expense, net in the condensed consolidated statements of operations and comprehensive loss, and currency translation adjustment, recorded within the Other comprehensive loss, for the three months ended March 31, 2021 and 2020:

	March 31, 2021			March 31, 2020
Fair value adjustment - (Gain)	$	(425	)	$	(1,617	)
Currency translation adjustment - (Gain)		(1,664	)		(537	)

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Restricted cash (Tables)

3 Months Ended

Mar. 31, 2021

Restricted cash [Abstract]

Restricted Cash

As of March 31, 2021 and December 31, 2020, restricted cash consisted of the following:

	March 31, 2021		December 31, 2020
Collateral for performance under customer agreements	$	15,000	$	15,000
Collateral for LNG purchases		2,916		11,664
Collateral for letters of credit and performance bonds		906		900
Other restricted cash		250		250
Total restricted cash	$	19,072	$	27,814
Current restricted cash	$	4,072	$	12,814
Non-current restricted cash		15,000		15,000

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Inventory (Tables)

3 Months Ended

Mar. 31, 2021

Inventory [Abstract]

Inventory

As of March 31, 2021 and December 31, 2020, inventory consisted of the following:

	March 31, 2021		December 31, 2020
LNG and natural gas inventory	$	18,213	$	13,986
Automotive diesel oil inventory		4,463		3,986
Bunker fuel, materials, supplies and other		5,355		4,888
Total inventory	$	28,031	$	22,860

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Prepaid expenses and other current assets (Tables)

3 Months Ended

Mar. 31, 2021

Prepaid expenses and other current assets [Abstract]

Prepaid Expenses and Other Current Assets, Net

As of March 31, 2021 and December 31, 2020, prepaid expenses and other current assets consisted of the following:

	March 31, 2021		December 31, 2020
Prepaid LNG	$	20,605	$	11,987
Prepaid expenses		6,806		4,941
Due from affiliates (Note 20)		1,912		1,881
Other current assets		30,922		29,461
Total prepaid expenses and other current assets, net	$	60,245	$	48,270

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Construction in progress (Tables)

3 Months Ended

Mar. 31, 2021

Construction in progress [Abstract]

Construction in Progress Activity

The Company’s construction in progress activity during the three months ended March 31, 2021 is detailed below:

	March 31, 2021
Balance at beginning of period	$	234,037
Additions		105,761
Transferred to property, plant and equipment, net or finance leases		(2,107	)
Balance at end of period	$	337,691

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Property, plant and equipment, net (Tables)

3 Months Ended

Mar. 31, 2021

Property, plant and equipment, net [Abstract]

Property, Plant and Equipment, Net

As of March 31, 2021 and December 31, 2020, the Company’s property, plant and equipment, net consisted of the following:

	March 31, 2021			December 31, 2020
Terminal and power plant equipment	$	189,197		$	188,855
CHP facilities		119,723			119,723
Gas terminals		120,810			120,810
ISO containers and other equipment		102,010			100,137
LNG liquefaction facilities		63,213			63,213
Gas pipelines		58,974			58,974
Land		16,582			16,246
Leasehold improvements		8,723			8,723
Accumulated depreciation		(72,229	)		(62,475	)
Total property, plant and equipment, net	$	607,003		$	614,206

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Intangible assets (Tables)

3 Months Ended

Mar. 31, 2021

Intangible assets [Abstract]

Composition of Intangible Assets

The following table summarizes the composition of intangible assets as of March 31, 2021 and December 31, 2020:

	March 31, 2021
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
Permits	$	49,467	$	2,607	$	46,860		38
Acquired power purchase agreements		16,499		-		16,499		17
Easements		1,559		203		1,356		30
Indefinite-lived intangible assets
Easements		1,219		-		1,219		n/a
Total intangible assets	$	68,744	$	2,810	$	65,934

	December 31, 2020
	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount		Weighted Average Life
Definite-lived intangible assets
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

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Other non-current assets (Tables)

3 Months Ended

Mar. 31, 2021

Other non-current assets [Abstract]

Other Non-Current Assets

As of March 31, 2021 and December 31, 2020, Other non-current assets consisted of the following:

	March 31, 2021		December 31, 2020
Nonrefundable deposit	$	30,728	$	28,509
Contract asset, net (Note 4)		30,685		23,972
Cost to fulfill (Note 4)		10,830		10,688
Unbilled receivables, net (Note 4)		6,373		6,462
Upfront payments to customers		10,501		6,330
Other		25,023		10,069
Total other non-current assets, net	$	114,140	$	86,030

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Accrued liabilities (Tables)

3 Months Ended

Mar. 31, 2021

Accrued liabilities [Abstract]

Accrued Liabilities

As of March 31, 2021 and December 31, 2020, accrued liabilities consisted of the following:

	March 31, 2021		December 31, 2020
Accrued development costs	$	25,222	$	16,631
Accrued interest		3,516		27,938
Accrued bonuses		6,171		17,344
Other accrued expenses		53,900		28,439
Total accrued liabilities	$	88,809	$	90,352

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Debt (Tables)

3 Months Ended

Mar. 31, 2021

Debt [Abstract]

Long-term Debt

As of March 31, 2021 and December 31, 2020, debt consisted of the following:

	March 31, 2021		December 31, 2020
Senior Secured Notes, due September 15, 2025	$	1,239,799	$	1,239,561
Total debt	$	1,239,799	$	1,239,561

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 three months ended March 31, 2021 and 2020 consisted of the following:

	Three Months Ended March 31,
	2021		2020
Interest per contractual rates	$	20,834	$	18,874
Amortization of debt issuance costs		487		4,622
Total interest costs		21,321		23,496
Capitalized interest		2,641		9,606
Total interest expense	$	18,680	$	13,890

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Earnings per share (Tables)

3 Months Ended

Mar. 31, 2021

Earnings per share [Abstract]

Earnings Per Share

	Three Months Ended March 31,
	2021			2020
Numerator:
Net loss	$	(39,509	)	$	(60,223	)
Less: net loss attributable to non-controlling interests		1,606			51,757
Net loss attributable to Class A common stock	$	(37,903	)	$	(8,466	)
Denominator:
Weighted-average shares-basic and diluted		176,500,576			26,029,492
Net loss per share - basic and diluted	$	(0.21	)	$	(0.32	)

Dilutive Securities Excluded from Computation of Diluted Net Loss Per Share Effects Presented in Anti-dilutive

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.

	Three Months Ended March 31,
	2021		2020
Unvested RSUs1		869,262		1,890,125
Class B shares2		-		144,342,572
Shannon Equity Agreement shares3		464,267		1,635,462
Total		1,333,529		147,868,159

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. In connection with the closing of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares.

³ Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

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Share-based compensation (Tables)

3 Months Ended

Mar. 31, 2021

Share-based compensation [Abstract]

RSU Activity

The following table summarizes the RSU activity for the three months ended March 31, 2021:

	Restricted Share Units			Weighted-average grant date fair value per share
Non-vested RSUs as of December 31, 2020		1,538,060		$	13.49
Granted		-			-
Vested		(665,781	)		13.54
Forfeited		(3,017	)		13.51
Non-vested RSUs as of March 31, 2021		869,262		$	13.45

Share-based Compensation Expense

The following table summarizes the share-based compensation expense for the Company’s RSUs recorded for the three  months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021		2020
Operations and maintenance	$	222	$	237
Selling, general and administrative		1,548		2,271
Total share-based compensation expense	$	1,770	$	2,508

PSU Activity

Performance Share Units (“PSUs”)

During the first quarter of 2020 and 2021, the Company granted PSUs to certain employees and non-employees that contain a performance condition. Vesting will be determined based on achievement of a performance metric for the year subsequent to the grant, and the number of shares that will vest can range from zero to a multiple of units granted. For the three months ended March 31, 2021, 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 condensed consolidated statements of operations and comprehensive loss

PSUs Granted	Units Granted	Range of Vesting	Unrecognized Compensation Cost(1)		Weighted Average Remaining Vesting Period
Q1 2020	1,109,777	0 to 2,219,554	$	30,864	0.75 years
Q1 2021	400,507	0 to 801,014	$	32,577	1.75 years

(1) Unrecognized compensation cost is based upon the maximum amount of shares that could vest

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Related party transactions (Tables)

3 Months Ended

Mar. 31, 2021

Related party transactions [Abstract]

Due to/from Affiliates

The table below summarizes the balances outstanding with affiliates as of March 31, 2021 and December 31, 2020:

	March 31, 2021		December 31, 2020
Amounts due to affiliates	$	10,859	$	8,980
Amounts due from affiliates		1,912		1,881

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Organization (Details)	3 Months Ended
	Mar. 31, 2021 Segment
Organization [Abstract]
Number of operating segments	1

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Significant accounting policies (Details) $ / shares in Units, $ in Millions					3 Months Ended
	Aug. 07, 2020 $ / shares shares	Jun. 10, 2020 shares	Mar. 01, 2019 USD ($) $ / shares shares	Feb. 04, 2019 USD ($) $ / shares shares	Mar. 31, 2021 Obligation $ / shares shares	Dec. 31, 2020 $ / shares shares
Basis of presentation and principles of consolidation [Abstract]
Percentage of voting and non-economic interest				88.00%
Percentage of economic interest in NFI				88.00%
Exchange transactions completion date					Jun. 10, 2020
Number of LLC shares converted to Corporate shares (in shares)	1
Par value per share (in dollars per share) | $ / shares	$ 0.01
Revenue recognition [Abstract]
Number of performance obligations | Obligation					1
Class A [Member]
Basis of presentation and principles of consolidation [Abstract]
Shares outstanding (in shares)					175,320,414	174,600,000
Shares issued in exchange of NFI units (in shares)		144,342,572
Par value per share (in dollars per share) | $ / shares					$ 0.01	$ 0.01
Class A [Member] | IPO [Member]
Basis of presentation and principles of consolidation [Abstract]
Shares issued in initial public offering (in shares)			837,272	20,000,000
IPO price per share (in dollars per share) | $ / shares			$ 14.00	$ 14.00
Net proceeds from initial public offering | $			$ 11.0	$ 257.0
Shares outstanding (in shares)			20,837,272
Underwriting discounts and commissions | $			$ 0.7
Class B [Member]
Basis of presentation and principles of consolidation [Abstract]
Shares outstanding (in shares)					0
Shares issued in exchange of NFI units (in shares)		144,342,572
Class B [Member] | IPO [Member]
Basis of presentation and principles of consolidation [Abstract]
Effects of reorganization transactions (in shares)				147,058,824
Shares outstanding (in shares)				147,058,824

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Revenue from contracts with customers (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Revenue from contracts with customers [Abstract]
Receivables, revenue from contracts with customers	$ 95,753		$ 76,431
Current expected credit losses	203		98
Contract with Customer, Asset and Liability [Abstract]
Contract assets, net - current	5,268		3,673
Contract assets, net - non-current	30,685		23,972
Total contract assets, net	35,953		27,645
Contract liabilities	10,704		8,399
Revenue recognized in the year from [Abstract]
Amounts included in contract liabilities at the beginning of the year	942		6,542
Contract assets net of current expected credit losses	484		372
Unbilled receivables net of current expected credit losses	6,729
Unbilled receivables included in other current assets	356
Unbilled receivables included in other non-current asset	6,373
Disaggregation of Revenue [Abstract]
Operating revenue	91,196	$ 63,502
Other revenues	54,488	11,028
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	10,478,395
Capitalized Contract Cost [Abstract]
Capitalized contract costs	11,434		11,276
Other current assets	604		588
Other noncurrent assets	10,830		$ 10,688
Development Services [Member]
Disaggregation of Revenue [Abstract]
Other revenues	54,071	10,071
Development Services [Member] | Natural Gas Used In Commissioning [Member]
Disaggregation of Revenue [Abstract]
Other revenues	45,618
Lease and Other Revenue [Member]
Disaggregation of Revenue [Abstract]
Other revenues	417	$ 957
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-04-01
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	$ 278,546
Remaining performance obligation, expected timing of satisfaction, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	$ 504,522
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	$ 504,708
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	$ 499,842
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	$ 494,081
Remaining performance obligation, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Performance Obligation Satisfied over Time [Abstract]
Remaining performance obligation	$ 8,196,696
Remaining performance obligation, expected timing of satisfaction, period	1 year

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Leases, Components of Operating Lease Costs (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Operating lease cost [Abstract]
Fixed lease cost	$ 11,745	$ 10,267
Variable lease cost	693	639
Short-term lease cost	722	286
Lease cost - Cost of sales	11,036	9,351
Lease cost - Operations and maintenance	557	388
Lease cost - Selling, general and administrative	1,567	$ 1,453
Capitalized lease cost	$ 1,199

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Leases, Lessee Operating Lease Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Supplemental cash flow information related to leases [Abstract]
Operating cash outflows for operating lease liabilities	$ 12,660	$ 10,096
Right-of-use assets obtained in exchange for new operating lease liabilities	$ 0	$ 127,994

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Leases, Future Payments Due under Operating Leases (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Future minimum payments of operating lease liability [Abstract]
Due remainder of 2021	$ 30,754
2022	29,931
2023	18,719
2024	17,866
2025	10,680
Thereafter	50,019
Total lease payments	157,969
Less: effects of discounting	48,749
Present value of lease liabilities	109,220
Current lease liability	34,857	$ 35,481
Non-current lease liability	$ 74,363	$ 84,323
Weighted-average remaining lease term	7 years 3 months 18 days
Weighted average discount rate	8.40%
Noncancelable term for ISO tanks	5 years
Fixed payments for lease components	$ 24,000

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Leases, Property, Plant and Equipment Subject to Operating Leases (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment Subjected to Operating Lease [Abstract]
Total property, plant and equipment, net	$ 607,003	$ 614,206
Lessor [Member]
Property, Plant and Equipment Subjected to Operating Lease [Abstract]
Property, plant and equipment	18,747	18,394
Accumulated depreciation	(1,189)	(932)
Total property, plant and equipment, net	$ 17,558	$ 17,462

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Leases, Expected Future Lease Payments (Details) $ in Thousands	Mar. 31, 2021 USD ($)
Financing leases, lease receivable, fiscal year maturity [Abstract]
Remainder of 2021	$ 1,671
2022	2,149
2023	2,134
2024	2,135
2025	2,001
Thereafter	5,705
Total	15,795
Less: Imputed interest	6,718
Present value of total lease receipts	9,077
Current finance leases, net	1,576
Non-current finance leases, net	7,501
Operating lease, payments, fiscal year maturity [Abstract]
Reminder of 2021	220
2022	286
2023	288
2024	273
2025	234
Thereafter	743
Total	$ 2,044

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Fair value (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Assets [Abstract]
Restricted cash		$ 19,072		$ 27,814
Fair Value Adjustment and Currency Translation Adjustment [Abstract]
Fair value adjustment - (Gain)		(425)	$ (1,617)
Currency translation adjustment - (Gain)		(1,664)	$ (537)
Asset acquisition		10,520
2025 Notes [Member]
Fair Value Adjustment and Currency Translation Adjustment [Abstract]
Fair value of notes		1,285,588
Market Approach [Member]
Assets [Abstract]
Cash and cash equivalents		360,130		601,522
Restricted cash		19,072		27,814
Investment in equity securities		2,143		1,256
Total		381,345		630,592
Income Approach [Member]
Liabilities [Abstract]
Derivative liability	[1]	20,692		10,716
Equity agreement	[2]	21,223		22,768
Total		41,915		33,484
Level 1 [Member] | Market Approach [Member]
Assets [Abstract]
Cash and cash equivalents		360,130		601,522
Restricted cash		19,072		27,814
Investment in equity securities		294		256
Total		379,496		629,592
Level 1 [Member] | Income Approach [Member]
Liabilities [Abstract]
Derivative liability	[1]	0		0
Equity agreement	[2]	0		0
Total		0		0
Level 2 [Member] | Market Approach [Member]
Assets [Abstract]
Cash and cash equivalents		0		0
Restricted cash		0		0
Investment in equity securities		0		0
Total		0		0
Level 2 [Member] | Income Approach [Member]
Liabilities [Abstract]
Derivative liability	[1]	0		0
Equity agreement	[2]	0		0
Total		0		0
Level 3 [Member] | Market Approach [Member]
Assets [Abstract]
Cash and cash equivalents		0		0
Restricted cash		0		0
Investment in equity securities		1,849		1,000
Total		1,849		1,000
Level 3 [Member] | Income Approach [Member]
Liabilities [Abstract]
Derivative liability	[1]	20,692		10,716
Equity agreement	[2]	21,223		22,768
Total		$ 41,915		$ 33,484

[1] Consideration due to the sellers in assets acquistions when certain contingent events occur.

[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.

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Restricted cash (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Restricted cash [Abstract]
Collateral for performance under customer agreements	$ 15,000	$ 15,000
Collateral for LNG purchases	2,916	11,664
Collateral for letters of credit and performance bonds	906	900
Other restricted cash	250	250
Total restricted cash	19,072	27,814
Current restricted cash	4,072	12,814
Non-current restricted cash	$ 15,000	$ 15,000

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Inventory (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Inventory [Abstract]
LNG and natural gas inventory	$ 18,213		$ 13,986
Automotive diesel oil inventory	4,463		3,986
Bunker fuel, materials, supplies and other	5,355		4,888
Total inventory	28,031		$ 22,860
Inventory adjustments	$ 0	$ 0

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Prepaid expenses and other current assets (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Prepaid expenses and other current assets [Abstract]
Prepaid LNG	$ 20,605	$ 11,987
Prepaid expenses	6,806	4,941
Due from affiliates (Note 20)	1,912	1,881
Other current assets	30,922	29,461
Total prepaid expenses and other current assets, net	$ 60,245	$ 48,270

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Construction in progress (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Construction in Progress [Roll Forward]
Balance at beginning of period	$ 234,037
Additions	105,761
Transferred to property, plant and equipment, net or finance leases	(2,107)
Balance at end of period	337,691
Interest costs capitalized	$ 2,641	$ 9,606

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Property, plant and equipment, net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation	$ (72,229)		$ (62,475)
Total property, plant and equipment, net	607,003		614,206
Depreciation	9,842	$ 5,211
Cost of Sales [Member]
Property, Plant and Equipment, Net [Abstract]
Depreciation	270	$ 227
Terminal and Power Plant Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	189,197		188,855
CHP Facilities [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	119,723		119,723
Gas Terminals [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	120,810		120,810
ISO Containers and Other Equipment [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	102,010		100,137
LNG Liquefaction Facilities [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	63,213		63,213
Gas Pipelines [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	58,974		58,974
Land [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	16,582		16,246
Leasehold Improvements [Member]
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment, gross	$ 8,723		$ 8,723

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Intangible assets (Details) - USD ($) $ in Thousands			3 Months Ended		12 Months Ended
	Mar. 11, 2021	Jan. 12, 2021	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Intangible Assets, Net [Abstract]
Definite-Lived Intangible Assets, Accumulated Amortization			$ 2,810		$ 2,628
Total Intangible Assets, Gross Carrying Amount			68,744		48,730
Total Intangible Assets, Net Carrying Amount			$ 65,934		$ 46,102
Weighted average remaining amortization period for intangible assets			31 years		37 years 6 months
Amortization expense			$ 295	$ 270
CH4 Energia Ltda. [Member]
Intangible Assets, Net [Abstract]
Asset acquisition		$ 4,245	5,776
Pecem Energia S.A. and Energetica Camacari Muricy II S.A. [Member]
Intangible Assets, Net [Abstract]
Asset acquisition	$ 16,585		16,585
Easements [Member]
Intangible Assets, Net [Abstract]
Indefinite-Lived Intangible Assets, Carrying Amount			1,219		$ 1,274
Permits [Member]
Intangible Assets, Net [Abstract]
Definite-Lived Intangible Assets, Gross Carrying Amount			49,467		45,897
Definite-Lived Intangible Assets, Accumulated Amortization			2,607		2,438
Definite-Lived Intangible Assets, Net Carrying Amount			$ 46,860		$ 43,459
Definite-Lived Intangible Assets, Weighted Average Life			38 years		40 years
Acquired Power Purchase Agreements [Member]
Intangible Assets, Net [Abstract]
Definite-Lived Intangible Assets, Gross Carrying Amount			$ 16,499
Definite-Lived Intangible Assets, Accumulated Amortization			0
Definite-Lived Intangible Assets, Net Carrying Amount			$ 16,499
Definite-Lived Intangible Assets, Weighted Average Life			17 years
Easements [Member]
Intangible Assets, Net [Abstract]
Definite-Lived Intangible Assets, Gross Carrying Amount			$ 1,559		$ 1,559
Definite-Lived Intangible Assets, Accumulated Amortization			203		190
Definite-Lived Intangible Assets, Net Carrying Amount			$ 1,356		$ 1,369
Definite-Lived Intangible Assets, Weighted Average Life			30 years		30 years

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Other non-current assets (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021 USD ($) SalesContract	Dec. 31, 2020 USD ($)
Other non-current assets [Abstract]
Nonrefundable deposit	$ 30,728	$ 28,509
Contract asset, net (Note 4)	30,685	23,972
Cost to fulfill (Note 4)	10,830	10,688
Unbilled receivables, net (Note 4)	6,373	6,462
Upfront payments to customers	10,501	6,330
Other	25,023	10,069
Total other non-current assets, net	$ 114,140	86,030
Number of sales contracts | SalesContract	2
SAFE [Member]
Other Assets, Noncurrent [Abstract]
Investment in equity securities	$ 750	$ 1,000

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Accrued liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Accrued liabilities [Abstract]
Accrued development costs	$ 25,222	$ 16,631
Accrued interest	3,516	27,938
Accrued bonuses	6,171	17,344
Other accrued expenses	53,900	28,439
Total accrued liabilities	$ 88,809	$ 90,352

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Debt (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Long-term Debt, Current and Noncurrent [Abstract]
Debt	$ 1,239,799	$ 1,239,561
Senior Secured Notes, due September 15, 2025 [Member]
Long-term Debt, Current and Noncurrent [Abstract]
Debt	$ 1,239,799	$ 1,239,561
Maturity date	Sep. 15, 2025

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Debt, 2025 Senior Secured Notes (Details) - 2025 Senior Secured Notes [Member] - USD ($) $ in Thousands		3 Months Ended
	Dec. 17, 2020	Mar. 31, 2021	Sep. 30, 2020	Sep. 02, 2020
Senior Secured Notes [Abstract]
Debt instrument, issued	$ 250,000			$ 1,000,000
Fixed interest rate				6.75%
Frequency of payments		semi-annually
Maturity date		Sep. 15, 2025
Fees incurred				$ 17,937
Reduction in principal balance		$ 13,909
Remaining unamortized deferred financing costs		$ 10,201		$ 6,501
Third party fees			$ 4,028
Proceeds from premium on issuance of secured debt	13,125
Additional financing costs incurred	$ 4,436

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Debt, The Credit Agreement (Details) - USD ($) $ in Thousands			3 Months Ended
	Sep. 02, 2020	Jan. 10, 2020	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2018	Aug. 16, 2018
Credit Agreement [Abstract]
Loss on extinguishment of debt			$ 0	$ 9,557
Credit Agreement [Member]
Credit Agreement [Abstract]
Aggregate principal amount		$ 800,000
Debt maturity date			Jan. 15, 2023
Variable interest rate		6.25%
Increase in interest rate		1.50%
Reduction in principal balance	$ 6,501	$ 37,051
Loss on extinguishment of debt	$ (16,310)
Credit Agreement [Member] | Interest Rate Floor [Member]
Credit Agreement [Abstract]
Variable interest rate		1.50%
Term Loan Facility, due January 21, 2020 [Member]
Credit Agreement [Abstract]
Aggregate principal amount					$ 500,000	$ 240,000
Variable interest rate			4.00%
Increase in interest rate			0.50%
Proceeds used to extinguish debt		$ 495,000
Loss on extinguishment of debt			$ 9,557

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Debt, Term Loan Facility (Details) $ in Thousands		3 Months Ended
	Mar. 21, 2019 USD ($)	Mar. 31, 2021 USD ($) Extension	Mar. 31, 2020 USD ($)	Dec. 31, 2018 USD ($)	Aug. 16, 2018 USD ($) Lender
Term Loan Facility [Abstract]
Loss on extinguishment of debt		$ 0	$ (9,557)
Term Loan Facility, due January 21, 2020 [Member]
Term Loan Facility [Abstract]
Number of lenders | Lender					2
Aggregate principal amount				$ 500,000	$ 240,000
Outstanding borrowings	$ 500,000			$ 280,000
Additional borrowing amount	$ 220,000
Debt instrument, basis spread on variable rate		4.00%
Debt instrument, frequency of periodic payment		quarterly
Debt instrument, periodic payment		$ 1,250
Number of extensions for maturity date | Extension		2
Additional extended maturity period		6 months
Percentage of fee payable in outstanding principal for extension of maturity date		1.00%
Increase in interest rate		0.50%
Loss on extinguishment of debt		$ (9,557)
Term Loan Facility, due January 21, 2020 [Member] | Floor Rate [Member]
Term Loan Facility [Abstract]
Debt instrument, basis spread on variable rate		1.00%
Term Loan Facility, due January 21, 2020 [Member] | Federal Funds Rate [Member]
Term Loan Facility [Abstract]
Debt instrument, basis spread on variable rate		0.50%
Term Loan Facility, due January 21, 2020 [Member] | LIBOR [Member]
Term Loan Facility [Abstract]
Debt instrument, basis spread on variable rate		1.00%
Debt instrument, term of variable rate		1 month
Interest rate plus spread		3.00%

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Debt, South Power Bonds (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended		12 Months Ended
	Sep. 21, 2020	Jan. 31, 2020	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2019	Sep. 02, 2019
Senior Secured and Unsecured Bonds [Abstract]
Loss on extinguishment of debt			$ 0	$ (9,557)
Senior Secured Bonds [Member] | South Power [Member]
Senior Secured and Unsecured Bonds [Abstract]
Debt instrument, issued						$ 73,317
Debt instrument, issuable upon completion of certain conditions					$ 63,000
Proceeds from issuance of bonds		$ 52,144			$ 10,856
Fixed interest rate			8.25%
Maturity period			15 years
Non-payment of principal due period			7 years
Frequency of payments			quarterly
Percentage of balloon payment due upon maturity			50.00%
Senior Unsecured Bonds [Member] | South Power [Member]
Senior Secured and Unsecured Bonds [Abstract]
Debt instrument, issued						$ 43,683
Fixed interest rate			11.00%
Maturity date			Sep. 30, 2036
Non-payment of principal due period			9 years
Frequency of payments			quarterly
Senior Secured Bonds and Senior Unsecured Bonds [Member] | South Power [Member]
Senior Secured and Unsecured Bonds [Abstract]
Fees paid			$ 3,892
Loss on extinguishment of debt	$ (7,195)
Unamortized deferred financing costs, write-off	3,594
Prepayment Premium Paid to Bondholders	$ 3,601

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Debt, Interest Expense (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Interest costs [Abstract]
Amortization of debt issuance costs	$ 400	$ 3,353
Total interest expense	18,680	13,890
Debt [Member]
Interest costs [Abstract]
Interest per contractual rates	20,834	18,874
Amortization of debt issuance costs	487	4,622
Total interest costs	21,321	23,496
Capitalized interest	2,641	9,606
Total interest expense	$ 18,680	$ 13,890

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Income taxes (Details) - USD ($) $ in Thousands		3 Months Ended
	Jun. 10, 2020	Mar. 31, 2021	Mar. 31, 2020
Loss before Income Taxes [Abstract]
Percentage of NFI operations included in income tax provision	100.00%
Effective tax rate		2.20%	0.01%
Tax expense (benefit)		$ (877)	$ (4)
Income tax expense (benefit), discrete (benefit)		$ (3,010)
Statutory tax rate		21.00%	21.00%
Uncertain tax positions		$ 0

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Earnings per share (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Numerator [Abstract]
Net loss		$ (39,509)	$ (60,223)
Less: net loss attributable to non-controlling interests		1,606	51,757
Net loss attributable to stockholders		$ (37,903)	$ (8,466)
Denominator [Abstract]
Weighted-average shares-basic (in shares)		176,500,576	26,029,492
Weighted-average shares-diluted (in shares)		176,500,576	26,029,492
Net loss per share - basic (in dollars per share)		$ (0.21)	$ (0.32)
Net loss per share - diluted (in dollars per share)		$ (0.21)	$ (0.32)
Dilutive Securities Excluded from Computation of Diluted Net Loss Per Share Effects Presented in Anti-dilutive [Abstract]
Anti-dilutive securities excluded from computation of diluted weighted average shares outstanding (in shares)		1,333,529	147,868,159
Dividend [Abstract]
Dividend declared		$ 17,598
Dividend per share (in dollars per share)		$ 0.10
Dividend paid		$ 17,657	$ 0
Class B Shares [Member]
Dilutive Securities Excluded from Computation of Diluted Net Loss Per Share Effects Presented in Anti-dilutive [Abstract]
Anti-dilutive securities excluded from computation of diluted weighted average shares outstanding (in shares)	[1]	0	144,342,572
Unvested RSUs [Member]
Dilutive Securities Excluded from Computation of Diluted Net Loss Per Share Effects Presented in Anti-dilutive [Abstract]
Anti-dilutive securities excluded from computation of diluted weighted average shares outstanding (in shares)	[2]	869,262	1,890,125
Shannon Equity Agreement Shares [Member]
Dilutive Securities Excluded from Computation of Diluted Net Loss Per Share Effects Presented in Anti-dilutive [Abstract]
Anti-dilutive securities excluded from computation of diluted weighted average shares outstanding (in shares)	[3]	464,267	1,635,462

[1] Class B shares at the end of the period are considered potentially dilutive Class A shares. In connection with the closing of the Exchange Transactions on June 10, 2020, all outstanding Class B shares were exchanged for Class A shares.

[2] Represents the number of instruments outstanding at the end of the period.

[3] Class A common stock that would be issued in relation to the Shannon LNG Equity Agreement.

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Share-based compensation (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended
		Mar. 31, 2021	Mar. 31, 2020
Restricted Stock Units [Member]
Number of Shares [Roll Forward]
Non-vested RSUs, beginning balance (in shares)		1,538,060
Granted (in shares)		0
Vested (in shares)		(665,781)
Forfeited (in shares)		(3,017)
Non-vested RSUs, ending balance (in shares)		869,262
Weighted Average Grant Date Fair Value Per Share [Abstract]
Non-vested RSUs, beginning balance (in dollars per share)		$ 13.49
Granted (in dollars per share)		0
Vested and shares issued (in dollars per share)		13.54
Forfeited (in dollars per share)		13.51
Non-vested RSUs, ending balance (in dollars per share)		$ 13.45
Share-based Payment Arrangement [Abstract]
Share-based compensation expense		$ 1,770	$ 2,508
Compensation expense recognized for forfeited RSU awards		0	61
Unrecognized compensation cost		$ 6,400
Weighted-average remaining vesting period of non-vested stock (in years)		1 year 18 days
Restricted Stock Units [Member] | Operations and Maintenance [Member]
Share-based Payment Arrangement [Abstract]
Share-based compensation expense		$ 222	237
Restricted Stock Units [Member] | Selling, General and Administrative Expenses [Member]
Share-based Payment Arrangement [Abstract]
Share-based compensation expense		$ 1,548	$ 2,271
Restricted Stock Units [Member] | Minimum [Member]
Share-based Payment Arrangement [Abstract]
Vesting period		10 months
Restricted Stock Units [Member] | Maximum [Member]
Share-based Payment Arrangement [Abstract]
Vesting period		3 years
Performance Share Units [Member] | Employees and Non-employees [Member]
Number of Shares [Roll Forward]
Granted (in shares)		400,507	1,109,777
Share-based Payment Arrangement [Abstract]
Unrecognized compensation cost	[1]	$ 32,577	$ 30,864
Weighted-average remaining vesting period of non-vested stock (in years)		1 year 9 months	9 months
Performance Share Units [Member] | Minimum [Member] | Employees and Non-employees [Member]
Number of Shares [Roll Forward]
Vested (in shares)		0	0
Performance Share Units [Member] | Maximum [Member] | Employees and Non-employees [Member]
Number of Shares [Roll Forward]
Vested (in shares)		(801,014)	(2,219,554)

[1] Unrecognized compensation cost is based upon the maximum amount of shares that could vest

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Related party transactions (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Related party transaction [Abstract]
Administrative and general expenses	$ 1,927	$ 2,231
Amount due to affiliates	10,859		$ 8,980
Charter costs	1,609	1,239
Lease liability	109,220
Amounts due from affiliates	1,912		1,881
Rent and administrative expenses	153
Rent and office related expenses incurred by affiliate	359		204
Noncurrent Lease Liabilities [Member]
Related party transaction [Abstract]
Lease liability	$ 3,288
DevTech Investment [Member]
Related party transaction [Abstract]
Minority interest percentage in exchange for cash consideration	10.00%
Percentage of note payable purchased by affiliate	10.00%
Note payable due	$ 715		715
Interest expense on note payable	21	19
Amounts due from affiliates	343		343
Fortress [Member]
Related party transaction [Abstract]
Amount due to affiliates	7,145		5,535
Fortress Affiliate [Member]
Related party transaction [Abstract]
Amount due to affiliates	554		472
Florida East Coast Industries [Member]
Related party transaction [Abstract]
Amount due to affiliates	0		316
Florida East Coast Industries [Member] | Land [Member] | Operations and Maintenance [Member]
Related party transaction [Abstract]
Lease expense	126	103
Fortress Affiliated Entities [Member]
Related party transaction [Abstract]
Amount due to affiliates	3,160		2,657
Amounts due from affiliates	1,210		$ 1,334
Rent and administrative expenses	$ 803	$ 1,165

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Related party transactions, Due to/from Affiliates (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Related party transactions [Abstract]
Amounts due to affiliates	$ 10,859	$ 8,980
Amounts due from affiliates	$ 1,912	$ 1,881

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Asset acquisitions (Details) - USD ($) $ in Thousands			3 Months Ended
	Mar. 11, 2021	Jan. 12, 2021	Mar. 31, 2021
CH4 Energia Ltda. [Member]
Business Combination, Description [Abstract]
Percentage of outstanding shares acquired		100.00%
Cash consideration at date of merger		$ 903
Maximum future payments contingent on achieving certain construction milestones		3,600
Fair value of contingent payments		3,047
Goodwill		0
Acquisition related costs		295
Total purchase consideration		4,245	$ 5,776
Deferred tax liability recognized on acquisition		$ 1,531
Pecem Energia S.A. and Energetica Camacari Muricy II S.A. [Member]
Business Combination, Description [Abstract]
Cash consideration at date of merger	$ 8,041
Maximum future payments contingent on achieving certain construction milestones	10,500
Fair value of contingent payments	7,473
Goodwill	0
Acquisition related costs	1,275
Total purchase consideration	$ 16,585		$ 16,585
Term of power purchase agreements	15 years
Maximum future payments payable to shareholders	$ 4,600
Pecem Energia S.A. [Member]
Business Combination, Description [Abstract]
Percentage of outstanding shares acquired	100.00%
Energetica Camacari Muricy II S.A. [Member]
Business Combination, Description [Abstract]
Percentage of outstanding shares acquired	100.00%

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Subsequent events (Details) - Subsequent Events [Member] - USD ($) $ / shares in Units, $ in Millions	Apr. 15, 2021	Apr. 12, 2021
Senior Secured Notes, due 2026 [Member]
Merger Agreement [Abstract]
Maturity date		Dec. 31, 2026
Fixed interest rate		6.50%
Percentage of notes issued		100.00%
Senior Secured Revolving Facility [Member]
Merger Agreement [Abstract]
Aggregate principal amount	$ 200
Debt instrument term	5 years
Senior Secured Revolving Facility [Member] | LIBOR [Member]
Merger Agreement [Abstract]
Term of variable rate	3 months
Private Offering [Member] | Senior Secured Notes, due 2026 [Member]
Merger Agreement [Abstract]
Aggregate principal amount		$ 1,500
Hygo Merger Agreement [Member] | Class A Common Stock [Member]
Merger Agreement [Abstract]
Cash consideration at date of merger	$ 580
Number of common stock, shares issuable upon merger transaction (in shares)	31,372,549
GMLP Merger Agreement [Member]
Merger Agreement [Abstract]
Purchase price (in dollars per share)	$ 3.55
Outstanding membership interests amount	$ 251